EX-99.3 4 a2021q4-exhibit993xmda.htm EX-99.3
Management Discussion & Analysis
Management of Algonquin Power & Utilities Corp. (“AQN” or the “Company” or the “Corporation”) has prepared the following discussion and analysis to provide information to assist its shareholders’ understanding of the financial results for the three and twelve months ended December 31, 2021. This Management Discussion & Analysis (“MD&A”) should be read in conjunction with AQN’s annual consolidated financial statements for the years ended December 31, 2021 and 2020. This material is available on SEDAR at www.sedar.com, on EDGAR at www.sec.gov/edgar, and on the AQN website at www.AlgonquinPowerandUtilities.com. Additional information about AQN, including the most recent Annual Information Form (“AIF”), can be found on SEDAR at www.sedar.com and on EDGAR at www.sec.gov/edgar.
Unless otherwise indicated, financial information provided for the years ended December 31, 2021 and 2020 has been prepared in accordance with generally accepted accounting principles in the United States (“U.S. GAAP”). As a result, the Company's financial information may not be comparable with financial information of other Canadian companies that provide financial information on another basis.
All monetary amounts are in U.S. dollars, except where otherwise noted. We denote any amounts denominated in Canadian dollars with "C$" immediately prior to the stated amount.
Capitalized terms used herein and not otherwise defined will have the meanings assigned to them in the Company's most recent AIF.
This MD&A is based on information available to management as of March 3, 2022.
Contents

Caution Concerning Forward-Looking Statements and Forward-Looking Information | 2
Caution Concerning Non-GAAP Measures | 4
Overview and Business Strategy | 6
Significant Updates | 9
Outlook | 12
2021 Fourth Quarter Results From Operations | 13
2021 Annual Results from Operations | 15
2021 Net Earnings Summary | 17
2021 Adjusted EBITDA Summary | 18
Regulated Services Group | 19
Renewable Energy Group | 29
AQN: Corporate and Other Expenses | 35
Non-GAAP Financial Measures | 37
Corporate Development Activities | 39
Summary of Property, Plant and Equipment Expenditures | 40
Liquidity and Capital Reserves | 42
Share-Based Compensation Plans | 46
Related Party Transactions | 48
Enterprise Risk Management | 49
Quarterly Financial Information | 66
Disclosure Controls and Internal Controls Over Financial Reporting | 67
Critical Accounting Estimates and Policies | 68

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Caution Concerning Forward-Looking Statements and Forward-Looking Information
This document may contain statements that constitute "forward-looking information" within the meaning of applicable securities laws in each of the provinces and territories of Canada and the respective policies, regulations and rules under such laws and/or "forward-looking statements" within the meaning of the U.S. Private Securities Litigation Reform Act of 1995 (collectively, “forward-looking information”). The words “anticipates”, “believes”, “budget”, “could”, “estimates”, “expects”, “forecasts”, “intends”, “may”, “might”, “plans”, “projects”, “schedule”, “should”, “will”, “would” and similar expressions are often intended to identify forward-looking information, although not all forward-looking information contains these identifying words. Specific forward-looking information in this document includes, but is not limited to, statements relating to: expected future growth, earnings (including 2022 Adjusted Net Earnings per common share) and results of operations; liquidity, capital resources and operational requirements; sources of funding, including adequacy and availability of credit facilities, debt maturation and future borrowings; expectations regarding the impact of the 2019 novel coronavirus (“COVID-19”) on the Company; expectations regarding the use of proceeds from financings; ongoing and planned acquisitions, projects and initiatives, including expectations regarding costs, financing, results, ownership structures, offtake arrangements, regulatory matters, in-service dates and completion dates; expectations regarding the anticipated closing of the Kentucky Power Transaction (as defined herein); expectations regarding the purchase price for the Kentucky Power Transaction and the expected financing thereof; the anticipated benefits of the Kentucky Power Transaction, including the impact of the Kentucky Power Transaction on the Corporation’s business, operations, financial condition, cash flows and results of operations; expectations regarding the Corporation’s and Kentucky Power’s (as defined herein) rate base; business mix and sustainability objectives following completion of the Kentucky Power Transaction; expectations regarding the timing for the transfer or retirement (for rate-making purposes in Kentucky) of the Mitchell Plant (as defined herein); expectations regarding cost recovery of amounts incurred by Empire in connection with the Midwest Extreme Weather Event (as defined herein) and retirement of the Asbury coal plant; expectations regarding the Company's corporate development activities and the results thereof, including the expected business mix between the Regulated Services Group and Renewable Energy Group; expectations regarding regulatory hearings, motions, filings, appeals and approvals, including rate reviews, and the impacts and outcomes thereof; expected future generation of the Company’s energy facilities; expected timing for signing a General Interconnection Agreement at the Neosho Ridge Wind Facility; statements regarding the Company’s sustainability and environmental, social and governance goals, including its net-zero by 2050 target; expected future capital investments, including expected timing, investment plans, sources of funds and impacts; expectations regarding future "greening the fleet" initiatives, including with respect to Kentucky Power; expectations regarding opportunities for the development of renewable natural gas facilities and cost recovery thereof; expectations regarding generation availability, capacity and production; expectations regarding the outcome of existing or potential legal and contractual claims and disputes; strategy and goals; dividends to shareholders; expectations regarding the impact of tax reforms; credit ratings and equity credit from rating agencies; anticipated customer benefits; the future impact on the Company of actual or proposed laws, regulations and rules; accounting estimates; interest rates and currency exchange rates. All forward-looking information is given pursuant to the “safe harbor” provisions of applicable securities legislation.
The forecasts and projections that make up the forward-looking information contained herein are based on certain factors or assumptions which include, but are not limited to: the receipt of applicable regulatory approvals and requested rate decisions; the absence of a material increase in the costs of compliance with environmental laws following the completion of the Kentucky Power Transaction; the absence of material adverse regulatory decisions being received and the expectation of regulatory stability; the absence of any material equipment breakdown or failure; availability of financing (including tax equity financing and self-monetization transactions for U.S. federal tax credits) on commercially reasonable terms and the stability of credit ratings of the Corporation and its subsidiaries; the absence of unexpected material liabilities or uninsured losses; the continued availability of commodity supplies and stability of commodity prices; the absence of sustained interest rate increases or significant currency exchange rate fluctuations; the absence of significant operational, financial or supply chain disruptions or liability; the continued ability to maintain systems and facilities to ensure their continued performance; the absence of a severe and prolonged downturn in general economic, credit, social or market conditions; the successful and timely development and construction of new projects; the closing of pending acquisitions substantially in accordance with the expected timing for such acquisitions; the absence of capital project or financing cost overruns; sufficient liquidity and capital resources; the continuation of long term weather patterns and trends; the absence of significant counterparty defaults; the continued competitiveness of electricity pricing when compared with alternative sources of energy; the realization of the anticipated benefits of the Corporation’s acquisitions and joint ventures; the absence of a change in applicable laws, political conditions, public policies and directions by governments, materially negatively affecting the Corporation; the ability to obtain and maintain licenses and permits; maintenance of adequate insurance coverage; the absence of material fluctuations in market energy prices; the absence of material disputes with taxation authorities or changes to applicable tax laws; continued maintenance of information technology infrastructure and the absence of a material breach of cybersecurity; favourable relations with external stakeholders; favourable labour relations; the realization of the anticipated benefits of the Kentucky Power Transaction, including that it will be accretive to the Corporation’s Adjusted Net Earnings per common share; that the Corporation will be able to successfully integrate newly acquired entities, and the absence of any material adverse changes to such entities prior to closing; the successful transfer of operational control over the Mitchell Plant to Wheeling Power Company; the transfer of the Mitchell Plant being implemented in accordance with the Corporation’s expectations; the absence of

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undisclosed liabilities of entities being acquired; that such entities will maintain constructive regulatory relationships with state regulatory authorities; the ability of the Corporation to retain key personnel of acquired entities and the value of such employees; no adverse developments in the business and affairs of the sellers during the period when transitional services are provided to the Corporation in connection with any acquisition; the ability of the Corporation to satisfy its liabilities and meet its debt service obligations following completion of any acquisition; the absence of any reputational harm to the Corporation as a result of any acquisition; and the ability of the Corporation to successfully execute future “greening the fleet” initiatives. Given the continued uncertainty and evolving circumstances surrounding the COVID-19 pandemic and related response from governments, regulatory authorities, businesses, suppliers and customers, there is more uncertainty associated with the Corporation’s assumptions and expectations as compared to periods prior to the onset of COVID-19.
The forward-looking information contained herein is subject to risks, uncertainties and other factors that could cause actual results to differ materially from historical results or results anticipated by the forward-looking information. Factors which could cause results or events to differ materially from current expectations include, but are not limited to: changes in general economic, credit, social or market conditions; changes in customer energy usage patterns and energy demand; global climate change; the incurrence of environmental liabilities; natural disasters, diseases, pandemics and other force majeure events; critical equipment breakdown or failure; supply chain disruptions; the failure of information technology infrastructure and cybersecurity; physical security breach; the loss of key personnel and/or labour disruptions; seasonal fluctuations and variability in weather conditions and natural resource availability; reductions in demand for electricity, gas and water due to developments in technology; reliance on transmission systems owned and operated by third parties; issues arising with respect to land use rights and access to the Corporation’s facilities; terrorist attacks; fluctuations in commodity prices; capital expenditures; reliance on subsidiaries; the incurrence of an uninsured loss; a credit rating downgrade; an increase in financing costs or limits on access to credit and capital markets; increases in interest rates; currency exchange rate fluctuations; restricted financial flexibility due to covenants in existing credit agreements; an inability to refinance maturing debt on commercially reasonable terms; disputes with taxation authorities or changes to applicable tax laws; failure to identify, acquire, develop or timely place in service projects to maximize the value of tax credits; requirement for greater than expected contributions to post-employment benefit plans; default by a counterparty; inaccurate assumptions, judgments and/or estimates with respect to asset retirement obligations; failure to maintain required regulatory authorizations; changes in, or failure to comply with, applicable laws and regulations; failure of compliance programs; failure to identify attractive acquisition or development candidates necessary to pursue the Corporation’s growth strategy; failure to dispose of assets (at all or at a competitive price) to fund the Company’s operations and growth plans; delays and cost overruns in the design and construction of projects, including as a result of COVID-19; loss of key customers; failure to complete or realize the anticipated benefits of acquisitions or joint ventures; Atlantica (as defined herein) or a third party joint venture partner acting in a manner contrary to the Corporation’s interests; a drop in the market value of Atlantica's ordinary shares; facilities being condemned or otherwise taken by governmental entities; increased external-stakeholder activism adverse to the Corporation’s interests; fluctuations in the price and liquidity of the Corporation’s common shares and the Corporation's other securities; the severity and duration of the COVID-19 pandemic and its collateral consequences, including the disruption of economic activity, volatility in capital and credit markets and legislative and regulatory responses; impact of significant demands placed on the Corporation as a result of pending acquisitions or growth strategies; potential undisclosed liabilities of any entities being acquired by the Corporation; uncertainty regarding the length of time required to complete pending acquisitions; the failure to implement the Corporation’s strategic objectives or achieve expected benefits relating to acquisitions; Kentucky Power’s failure to receive regulatory approval for the construction of new renewable generation facilities; indebtedness of any entity being acquired by the Corporation; reputational harm and increased costs of compliance with environmental laws as a result of announced or completed acquisitions; unanticipated expenses and/or cash payments as a result of change of control and/or termination for convenience provisions in agreements to which any entity being acquired is a party; and the reliance on third parties for certain transitional services following the completion of an acquisition. Although the Corporation has attempted to identify important factors that could cause actual actions, events or results to differ materially from those described in forward-looking information, there may be other factors that cause actions, events or results not to be as anticipated, estimated or intended. Some of these and other factors are discussed in more detail under the heading Enterprise Risk Management in this MD&A and under the heading Enterprise Risk Factors in the Corporation's most recent AIF.
Forward-looking information contained herein (including any financial outlook) is provided for the purposes of assisting the reader in understanding the Corporation and its business, operations, risks, financial performance, financial position and cash flows as at and for the periods indicated and to present information about management’s current expectations and plans relating to the future and the reader is cautioned that such information may not be appropriate for other purposes. Forward-looking information contained herein is made as of the date of this document and based on the plans, beliefs, estimates, projections, expectations, opinions and assumptions of management on the date hereof. There can be no assurance that forward-looking information will prove to be accurate, as actual results and future events could differ materially from those anticipated in such forward-looking information. Accordingly, readers should not place undue reliance on forward-looking information. While subsequent events and developments may cause the Corporation’s views to change, the Corporation disclaims any obligation to update any forward-looking information or to explain any material

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difference between subsequent actual events and such forward-looking information, except to the extent required by applicable law. All forward-looking information contained herein is qualified by these cautionary statements.
Caution Concerning Non-GAAP Measures
AQN uses a number of financial measures to assess the performance of its business lines. Some measures are calculated in accordance with U.S. GAAP, while other measures do not have a standardized meaning under U.S. GAAP. These non-GAAP measures include non-GAAP financial measures and non-GAAP ratios, each as defined in Canadian National Instrument 52-112 Non-GAAP and Other Financial Measures Disclosure. AQN’s method of calculating these measures may differ from methods used by other companies and therefore may not be comparable to similar measures presented by other companies.
The terms “Adjusted Net Earnings”, “Adjusted Earnings Before Interest, Taxes, Depreciation and Amortization” (“Adjusted EBITDA”), “Adjusted Funds from Operations”, "Net Energy Sales", "Net Utility Sales" and "Divisional Operating Profit", which are used throughout this MD&A, are non-GAAP financial measures. An explanation of each of these non-GAAP financial measures is set out below and a reconciliation to the most directly comparable U.S. GAAP measure, in each case, can be found in this MD&A. In addition, “Adjusted Net Earnings” is presented throughout this MD&A on a per share basis. Adjusted Net Earnings per common share is a non-GAAP ratio and is calculated by dividing Adjusted Net Earnings by the weighted average number of common shares outstanding during the applicable period.
Adjusted EBITDA
Adjusted EBITDA is a non-GAAP financial measure used by many investors to compare companies on the basis of ability to generate cash from operations. AQN uses these calculations to monitor the amount of cash generated by AQN. AQN uses Adjusted EBITDA to assess the operating performance of AQN without the effects of (as applicable): depreciation and amortization expense, income tax expense or recoveries, acquisition costs, certain litigation expenses, interest expense, gain or loss on derivative financial instruments, write down of intangibles and property, plant and equipment, earnings attributable to non-controlling interests, non-service pension and post-employment costs, cost related to tax equity financing, costs relat ed to management succession and executive retirement, costs related to prior period adjustments due to changes in tax law, cost s related to condemnation proceedings, financial impacts on the Company's Senate Wind Facility from the significantly elevated pricing that persisted in the Electric Reliability Council of Texas market over several days (the "Market Disruption Event") as a result of the February 2021 extreme winter storm conditions experienced in Texas and parts of the central U.S. (the “Midwest Extreme Weather Event”), gain or loss on foreign exchange, earnings or loss from discontinued operations, changes in value of investments carried at fair value, and other typically non-recurring or unusual items. AQN adjusts for these factors as they may be non-cash, unusual in nature and are not factors used by management for evaluating the operating performance of the Company. AQN believes that presentation of this measure will enhance an investor’s understanding of AQN’s operating performance. Adjusted EBITDA is not intended to be representative of cash provided by operating activities or results of operations determined in accordance with U.S. GAAP, and can be impacted positively or negatively by these items. For a reconciliation of Adjusted EBITDA to net earnings, see Non-GAAP Financial Measures starting on page 37 of this MD&A.
Adjusted Net Earnings
Adjusted Net Earnings is a non-GAAP financial measure used by many investors to compare net earnings from operations without the effects of certain volatile primarily non-cash items that generally have no current economic impact or items such as acquisition expenses or certain litigation expenses that are viewed as not directly related to a company’s operating performance. AQN uses Adjusted Net Earnings to assess its performance without the effects of (as applicable): gains or losses on foreign exchange, foreign exchange forward contracts, interest rate swaps, acquisition costs, one-time costs of arranging tax equity financing, certain litigation expenses and write down of intangibles and property, plant and equipment, earnings or loss from discontinued operations (excluding sale of assets in the course of normal operations), unrealized mark-to-market revaluation impacts (other than those realized in connection with the sales of development assets), costs related to management succession and executive retirement, costs related to prior period adjustments due to changes in tax law, costs related to condemnation proceedings, financial impacts from the Market Disruption Event on the Company's Senate Wind Facility, changes in value of investments carried at fair value, and other typically non-recurring or unusual items as these are not reflective of the performance of the underlying business of AQN. AQN believes that analysis and presentation of net earnings or loss on this basis will enhance an investor’s understanding of the operating performance of its businesses. Adjusted Net Earnings is not intended to be representative of net earnings or loss determined in accordance with U.S. GAAP, and can be impacted positively or negatively by these items. For a reconciliation of Adjusted Net Earnings to net earnings, see Non-GAAP Financial Measures starting on page 38 of this MD&A.
Adjusted Funds from Operations
Adjusted Funds from Operations is a non-GAAP financial measure used by investors to compare cash flows from operating activities without the effects of certain volatile items that generally have no current economic impact or items such as acquisition expenses that are viewed as not directly related to a company’s operating performance. AQN uses Adjusted

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Funds from Operations to assess its performance without the effects of (as applicable): changes in working capital balances, acquisition expenses, certain litigation expenses, cash provided by or used in discontinued operations, financial impacts from the Market Disruption Event on the Company's Senate Wind Facility, and other typically non-recurring items affecting cash from operations as these are not reflective of the long-term performance of the underlying businesses of AQN. AQN believes that analysis and presentation of funds from operations on this basis will enhance an investor’s understanding of the operating performance of its businesses. Adjusted Funds from Operations is not intended to be representative of cash flows from operating activities as determined in accordance with U.S. GAAP, and can be impacted positively or negatively by these items. For a reconciliation of Adjusted Funds from Operations to cash flows from operating activities, see Non-GAAP Financial Measures starting on page 39 of this MD&A.
Net Energy Sales
Net Energy Sales is a non-GAAP financial measure used by investors to identify revenue after commodity costs used to generate revenue where such revenue generally increases or decreases in response to increases or decreases in the cost of the commodity used to produce that revenue. AQN uses Net Energy Sales to assess its revenues without the effects of fluctuating commodity costs as such costs are predominantly passed through either directly or indirectly in the rates that are charged to customers. AQN believes that analysis and presentation of Net Energy Sales on this basis will enhance an investor’s understanding of the revenue generation of the Renewable Energy Group. It is not intended to be representative of revenue as determined in accordance with U.S. GAAP. For a reconciliation of Net Energy Sales to revenue, see Renewable Energy Group - 2021 Renewable Energy Group Operating Results on page 31 of this MD&A.
Net Utility Sales
Net Utility Sales is a non-GAAP financial measure used by investors to identify utility revenue after commodity costs, either natural gas or electricity, where these commodity costs are generally included as a pass through in rates to its utility customers. AQN uses Net Utility Sales to assess its utility revenues without the effects of fluctuating commodity costs as such costs are predominantly passed through and paid for by utility customers. AQN believes that analysis and presentation of Net Utility Sales on this basis will enhance an investor’s understanding of the revenue generation of the Regulated Services Group. It is not intended to be representative of revenue as determined in accordance with U.S. GAAP. For a reconciliation of Net Utility Sales to revenue, see Regulated Services Group - 2021 Regulated Services Group Operating Results on page 22 of this MD&A.
Divisional Operating Profit
Divisional Operating Profit is a non-GAAP financial measure . AQN uses Divisional Operating Profit to assess the operating performance of its business groups without the effects of (as applicable): depreciation and amortization expense, corporate administrative expenses, income tax expense or recoveries, acquisition costs, certain litigation expenses, interest expense, gain or loss on derivative financial instruments, write down of intangibles and property, plant and equipment, gain or loss on foreign exchange, earnings or loss from disconti nued operations (excluding the sale of assets in the course of normal operations), non-service pension and post-employment costs, financial impacts from the Market Disruption Event on the Company's Senate Wind Facility, and other typically non-recurring or unusual items. AQN adjusts for these factors as they may be non-cash, unusual in nature and are not factors used by management for evaluating the operating performance of the divisional units. Divisional Operating Profit is calculated inclusive of interest, dividend and equity income earned from indirect investments, and Hypothetical Liquidation at Book Value (“HLBV”) income, which represents the value of net tax attributes earned in the period from electricity generated by certain of its U.S. wind power and U.S. solar generation facilities. AQN believes that presentation of this measure will enhance an investor’s understanding of AQN’s divisional operating performance. Divisional Operating Profit is not intended to be representative of cash provided by operating activities or results of operations determined in accordance with U.S. GAAP, and can be impacted positively or negatively by these items. For a reconciliation of Divisional Operating Profit to revenue for AQN's main business units, see Regulated Services Group - 2021 Regulated Services Group Operating Results on page 22 an d Renewable Energy Group - 2021 Renewable Energy Group Operating Results on page 31 of this MD&A

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Overview and Business Strategy
AQN is incorporated under the Canada Business Corporations Act. AQN owns and operates a diversified portfolio of regulated and non-regulated generation, distribution, and transmission utility assets which are expected to deliver predictable earnings and cash flows. AQN seeks to maximize total shareholder value through real per share growth in earnings and cash flows to support a growing dividend and share price appreciation. AQN strives to achieve these results while also seeking to maintain a business risk profile consistent with its BBB flat investment grade credit ratings and a strong focus on Environmental, Social and Governance factors.
AQN’s current quarterly dividend to shareholders is $0.1706 per common share or $0.6824 per common share per annum. Based on the Bank of Canada exchange rate on March 2, 2022, the quarterly dividend is equivalent to C$0.2161 per common share or C$0.8644 per common share per annum. AQN believes its annual dividend payout allows for both an immediate return on investment for shareholders and retention of sufficient cash within AQN to fund growth opportunities. Changes in the level of dividends paid by AQN are at the discretion of AQN’s Board of Directors (the “Board”), with dividend levels being reviewed periodically by the Board in the context of AQN’s financial performance and growth prospects.
AQN’s operations are organized across two primary business units consisting of: the Regulated Services Group, which primarily owns and operates a portfolio of regulated assets in the United States, Canada, Bermuda and Chile, and the Renewable Energy Group, which primarily operates a diversified portfolio of owned renewable generation assets.
AQN pursues investment opportunities with an objective of maintaining the current business mix between its Regulated Services Group and Renewable Energy Group and with leverage consistent with its current credit ratings 1. The business mix target may from time to time require AQN to grow its Regulated Services Group or implement other strategies in order to pursue investment opportunities within its Renewable Energy Group.
The Company also undertakes development activities for both business units, working with a global reach to identify, develop, acquire, or invest in renewable power generating facilities, regulated utilities and other complementary infrastructure projects. See additional discussion in Corporate Development Activities.
Summary Structure of the Business
The following chart depicts, in summary form, AQN’s key businesses. A more detailed description of AQN’s organizational structure can be found in the most recent AIF.
1 See Treasury Risk Management -Downgrade in the Company's Credit Rating Risk.

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Regulated Services Group
The Regulated Services Group operates a diversified portfolio of regulated utility systems throughout the United States, Canada, Bermuda and Chile serving approximately 1,093,000 customer connections as at December 31, 2021 (using an average of 2.5 customers per connection, this translates into approximat ely 2,733,000 cu stomers). The Regulated Services Group seeks to provide safe, high quality, and reliable services to its customers and to deliver stable and predictable earnings to AQN. In addition to encouraging and supporting organic growth within its service territories, the Regulated Services Group seeks to deliver growth through accretive acquisitions of additional utility systems.
The Regulated Services Group's regulated electrical distribution utility systems and related generation assets are located in the U.S. States of California, New Hampshire, Missouri, Kansas, Oklahoma, and Arkansas, as well as in Bermuda, which together served approximately 307,000 electric customer connections as at December 31, 2021. The group also owns and operates generating assets with a gross capacity of approximately 2.0 GW and has investments in generating assets with approximately 0.3 GW of net generation capacity.
The Regulated Services Group's regulated natural gas distribution utility systems are located in the U.S. States of Georgia, Illinois, Iowa, Massachusetts, New Hampshire, Missouri, and New York, and in the Canadian Province of New Brunswick, which together served approximately 373,000 natural gas customer connections as at December 31, 2021.
The Regulated Services Group's regulated water distribution and wastewater collection utility systems are located in the U.S. States of Arizona, Arkansas, California, Illinois, Missouri, and Texas as well as in Chile which together served approximately 413,000 customer connections as at December 31, 2021. With the acquisition of New York American Water Company, Inc. (subsequently renamed Liberty Utilities (New York Water) Corp. (“Liberty NY Water”)), the Regulated Services Group added an additional approximately 125,000 customer connections in the state of New York effective January 1, 2022.
Below is a breakdown of the Regulated Services Group’s Revenue by geographic area for the twelve months ended December 31, 2021.

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Renewable Energy Group
The Renewable Energy Group generates and sells electrical energy produced by its diverse portfolio of renewable power generation and clean power generation facilities primarily located across the United States and Canada. The Renewable Energy Group seeks to deliver growth through development of new power generation projects and accretive acquisitions of additional power generation facilities, as well as the acquisition and development of other complementary projects, such as renewable natural gas (“RNG”) and energy storage.
The Renewable Energy Group directly owns and operates hydroelectric, wind, solar, and thermal facilities with a combined gross generating capacity of approximately 2.3 GW. Approximately 82% of the electrical output is sold pursuant to long term contractual arrangements which as of December 31, 2021 had a production-weighted average remaining contract life of approximately 12 years.
In addition to directly owned and operated assets, the Renewable Energy Group has investments in generating assets with approximately 1.4 GW of net generating capacity which includes the Company’s approximately 44% interest in Atlantica Sustainable Infrastructure plc (“Atlantica”). Atlantica owns and operates a portfolio of international clean energy and water infrastructure assets under long term contracts with a Cash Available for Distribution (CAFD) weighted average remaining contract life of approximately 15 years as of December 31, 2021.
Below is a breakdown of the Renewable Energy Group’s generating capacity by geographic area as of December 31, 2021, which was comprised of gross generating capacity of facilities owned and operated and net generating capacity of investments including the Company’s approximately 44% interest in Atlantica.

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Significant Updates
Operating Results
AQN operating results relative to the same period last year are as follows:

(all dollar amounts in $ millions except per share information) | Three months ended December 31 |  | Twelve months ended December 31 |  |
2021 |  | 2020 |  | Change |  | 2021 |  | 2020 |  | Change |  |  |  |  |  |
Net earnings attributable to shareholders | $175.6 |  | $504.2 |  | (65)% |  | $264.9 |  | $782.5 |  | (66)% |  |  |  |  |  |
Adjusted Net Earnings 1 | $136.3 |  | $127.0 |  | 7% |  | $449.6 |  | $365.8 |  | 23% |  |  |  |  |  |
Adjusted EBITDA 1 | $297.6 |  | $253.1 |  | 18% |  | $1,076.9 |  | $869.5 |  | 24% |  |  |  |  |  |
Net earnings per common share | $0.27 |  | $0.84 |  | (68)% |  | $0.41 |  | $1.38 |  | (70)% |  |  |  |  |  |
Adjusted Net Earnings per common share 1 | $0.21 |  | $0.21 |  | —% |  | $0.71 |  | $0.64 |  | 11% |  |  |  |  |  |

1 | See Caution Concerning Non-GAAP Measures.

Declaration of 2022 First Quarter Dividend of $0.1706 (C$0.2161) per Common Share
AQN currently targets annual growth in dividends payable to shareholders underpinned by increases in earnings and cash flow. In setting the appropriate dividend level, the Board considers the Company’s current and expected growth in earnings per share as well as a dividend payout ratio as a percentage of earnings per share and cash flow per share.
On March 3, 2022, AQN announced that the Board declared a first quarter 2022 dividend of $0.1706 per common share payable on April 14, 2022 to shareholders of record on March 31, 2022.
Based on the Bank of Canada exchange rate on March 2, 2022, the Canadian dollar equivalent for the first quarter 2022 dividend is C$0.2161 per common share.
The previous four quarter U.S and Canadian dollar equivalent dividends per common share have been as follows:

| Q2 2021 | Q3 2021 | Q4 2021 | Q1 2022 | Total
U.S. dollar dividend | $ | 0.1706 |  | $ | 0.1706 |  | $ | 0.1706 |  | $ | 0.1706 |  | $0.6824
Canadian dollar equivalent | $ | 0.2094 |  | $ | 0.2134 |  | $ | 0.2124 |  | $ | 0.2161 |  | $0.8513

Agreement to Acquire Kentucky Power Company and AEP Kentucky Transmission Company
On October 26, 2021, Liberty Utilities Co. (“Liberty Utilities”), an indirect subsidiary of AQN, entered into an agreement with American Electric Power Company, Inc. and AEP Transmission Company, LLC to acquire Kentucky Power Company (“Kentucky Power”) and AEP Kentucky Transmission Company, Inc. (“Kentucky TransCo”) for a total purchase price of approximately $2.846 billion, including the assumption of approximately $1.221 billion in debt (the “Kentucky Power Transaction”).
Kentucky Power is a state rate-regulated electricity generation, distribution and transmission utility serving approximately 228,000 active customer connections in 20 eastern Kentucky counties and operating under a cost of service framework. Kentucky TransCo is an electricity transmission business operating in the Kentucky portion of the transmission infrastructure that is part of the Pennsylvania – New Jersey – Maryland regional transmission organization, PJM Interconnection, L.L.C.. Kentucky Power and Kentucky TransCo are both regulated by the U.S. Federal Energy Regulatory Commission (“FERC”).
Closing of the Kentucky Power Transaction is subject to receipt of certain regulatory and governmental approvals, including the expiration or termination of any applicable waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976 (which has expired), clearance of the Kentucky Power Transaction by the Committee on Foreign Investment in the United States (which has been obtained), the approval by each of the Kentucky Public Service Commission and FERC with respect to the Kentucky Power Transaction and the termination and replacement of the existing operating agreement for the Mitchell coal generating facility (in which Kentucky Power owns a 50% interest, representing 780 MW) (the “Mitchell Plant”), and the approval of the Public Service Commission of West Virginia with respect to the termination and replacement of the existing operating agreement for the Mitchell Plant, and the satisfaction of other customary closing conditions. If the acquisition agreement is terminated in certain circumstances, including due to a failure to receive required regulatory approvals (other than the approval of the Kentucky Public Service Commission, FERC or the Public Service Commission of West Virginia for the termination and replacement of the existing operating agreement for the Mitchell Plant), the Corporation may be required to pay a termination fee of $65 million. The Kentucky Power Transaction is expected to close in mid-2022.

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The Kentucky Power Transaction is expected to add over $2.0 billion of regulated rate base assets in a favourable regulatory jurisdiction. AQN expects the Kentucky Power Transaction to be accretive to Adjusted Net Earnings per common share in the first full year of ownership, generate mid-single digit percentage Adjusted Net Earnings per common share accretion thereafter, and support growth in AQN’s Adjusted Net Earnings per common share over the long term (see Caution Concerning Non-GAAP Measures). Near and medium term planned retirements (for Kentucky rate-making purposes) or transitions of over 1 GW of fossil fuel generation owned by Kentucky Power are expected to provide the Company with an opportunity to leverage its “greening the fleet” capabilities as a renewable energy developer and target to replace this generation capacity with renewable energy.
Acquisition of Liberty NY Water (formerly New York American Water Company, Inc.)
Effective January 1, 2022, Liberty Utilities (Eastern Water Holdings) Corp., a wholly-owned subsidiary of Liberty Utilities, closed the previously-announced acquisition of Liberty NY Water from American Water Works Company, Inc. for a purchase price of approximately $608 million.
Headquartered in Merrick, NY, Liberty NY Water is a regulated water and wastewater utility serving over 125,000 customer connections across seven counties in southeastern New York. Liberty NY Water’s operations include approximately 1,270 miles of water mains and distribution lines, with 98% of customers located in Nassau County on Long Island.
Completion of Renewable Construction Projects
Completion of Midwest Greening the Fleet Initiative
On January 27, 2021, The Empire District Electric Company (“Empire”) closed its acquisition of the North Fork Ridge Wind Facility and, on May 5, 2021, Empire closed the acquisitions of the Kings Point and Neosho Ridge Wind Facilities (collectively, the “Empire Wind Facilities”.) As a result, the Regulated Services Group has successfully completed the construction and acquisition of all the wind facilities related to its Midwest ‘greening the fleet’ initiative. The initiative consisted of 600 MWs of new strategically located wind energy generation which is expected to provide benefits to the Regulated Services Group's electric customers in Missouri, Arkansas, Oklahoma and Kansas. The initiative also resulted in the early retirement of the 200 MW Asbury Coal Facility (Asbury”) on March 1, 2020, approximately 15 years ahead of its original retirement schedule.
The early retirement of Asbury is expected to provide long term benefits to customers and has reduced the Company's CO2e emissions by more than 900,000 metric tons, bringing the Company’s total reduction of greenhouse gas (“GHG”) emissions to over 1 million metric tons since 2017. The early retirement has also contributed to the reduction in the Company’s total Scope 1 GHG emissions as well as reductions in emission intensity per dollar of revenue since 2017, the year in which the Company acquired Empire, which owns Asbury. See Regulatory Proceedings.
Completion of the Maverick Creek Wind Project
On April 21, 2021, the Renewable Energy Group achieved full commercial operations (“COD”) at its 492 MW Maverick Creek Wind Facility, located in Concho County, Texas. The Maverick Creek Wind Facility is the Renewable Energy Group's 14th wind powered electric generating facility and is expected to generate approximately 1,920 GW-hrs of energy per year with the majority of output being sold through two long-term power purchase agreements (“PPA”s) with investment grade rated entities.
Completion of the Altavista Solar Project
On June 1, 2021, the Renewable Energy Group achieved COD at its 80 MW Altavista Solar Facility, located in Campbell County, Virginia. The Altavista Solar Facility is the Renewable Energy Group’s sixth solar powered electric generating facility and is expected to generate approximately 174 GW-hrs of energy per year with the majority of output being sold to Facebook Operations, LLC, a wholly-owned subsidiary of Meta, pursuant to a PPA.
Acquisition of Majority Interest in Texas Coastal Wind Facilities
In the first quarter of 2021, the Renewable Energy Group closed the acquisitions of a 51% interest in three of four wind facilities (collectively the “Texas Coastal Wind Facilities”) that it had previously agreed to purchase from RWE Renewables Americas, LLC, a subsidiary of RWE AG. The acquisition of a 51% interest in the fourth wind facility closed in the third quarter of 2021 when that facility achieved COD. The four Texas Coastal Wind Facilities have a total generating capacity of approximately 861 MW.

Algonquin Power & Utilities Corp. - Management Discussion & Analysis |

Agreement to Acquire Renewable Natural Gas Development Platform
On December 13, 2021, Liberty (RNG), LLC, a wholly-owned subsidiary of AQN, entered into an agreement to acquire Sandhill Advanced Biofuels, LLC (“Sandhill”). Sandhill is a renewable natural gas ("RNG") development platform specializing in anaerobic digestion projects located on dairy farms with a portfolio of four projects in the state of Wisconsin, two of which are currently under construction and the remaining two are in late-stage development. The existing projects are expected to produce RNG at a rate of approximately 500 one million British thermal units (“MMBTU”) per day. The transaction is expected to close in the first half of 2022. If successfully completed, the acquisition will represent the Company’s first investment in the non-regulated renewable natural gas space.
Corporate Financings Completed
Issuance of C$400 Million of Green Senior Unsecured Debentures
On April 9, 2021, the Renewable Energy Group issued C$400.0 million of green senior unsecured debentures bearing interest at 2.85% and with a maturity date of July 15, 2031 (the “Debentures”). Concurrent with the offering of the Debentures, the Renewable Energy Group entered into a cross currency interest rate swap to convert the proceeds into U.S. dollars with an effective interest rate throughout the term of the Debentures of approximately 2.82%. The net proceeds from the offering of the Debentures were or will be, as applicable, used in accordance with AQN’s Green Financing Framework.
Inaugural Issuance of Green Equity Units
On June 23, 2021, the Company closed an underwritten marketed public offering of 20,000,000 equity units (the “Green Equity Units”) for total gross proceeds of $1.0 billion. The underwriters subsequently exercised their option to purchase an additional 3,000,000 Green Equity Units on the same terms, bringing total gross proceeds including the over-allotment to $1.15 billion.
Each Green Equity Unit consists of a 1/20 or 5% undivided beneficial interest in a $1,000 principal amount remarketable senior note of the Company due June 15, 2026, and a contract to purchase AQN common shares on June 15, 2024 based on a reference price determined by the volume-weighted average AQN common share price over the preceding 20 day trading period. Total annual distributions on the Green Equity Units are at the rate of 7.75%. The net proceeds from the Offering have been or will be, as applicable, used to finance or refinance investments in renewable energy generation or facilities or other clean energy technologies in accordance with the Company’s Green Financing Framework. See additional discussion in Long Term Debt.
Common Equity Financing
On November 8, 2021, AQN closed a bought deal common equity offering for gross proceeds of approximately C$800 million (the “Common Equity Offering”). The Company intends to use the net proceeds of the Common Equity Offering to partially finance the Kentucky Power Transaction provided that, in the short-term, prior to closing of the Kentucky Power Transaction, the Company has used such net proceeds to reduce amounts outstanding under existing credit facilities.
Issuance of approximately $1.1 Billion of Subordinated Notes
Su bsequent to quarter-end on January 18, 2022, the Company closed (i) an underwritten public offering in the United States (the “U.S. Note Offering”) of $750 million aggregate principal amount of 4.75% fixed-to-fixed reset rate junior subordinated notes series 2022-B due January 18, 2082 (the “U.S. Notes”); and (ii) an underwritten public offering in Canada (the “Canadian Note Offering” and, together with the U.S. Note Offering, the “Note Offerings”) of C$400 million aggregate principal amount of 5.25% fixed-to-fixed reset rate junior subordinated notes series 2022-A due January 18, 2082 (the “Canadian Notes” and, together with the U.S. Notes, the “Notes”). The Company intends to use the net proceeds of the Note Offerings to partially finance the Kentucky Power Transaction provided that, in the short-term, prior to closing of the Kentucky Power Transaction, the Company has used a portion of, and expects to use the remainder of such net proceeds to repay certain indebtedness of the Corporation and its subsidiaries. Concurrent with the pricing of the Note Offerings, the Company entered into a cross currency interest rate swap, to convert the Canadian dollar denominated proceeds from the Canadian Note Offering into U.S. dollars and a forward starting swap to fix the interest rate for the secon d five year term of the U.S. Notes. resulting in an anticipated effective interest rate to the Company of approximately 4.95% throughout the first ten year period of the Notes.
Net-Zero Goals and 2021 ESG Report
On October 5, 2021, the Company announced its target to achieve net-zero (scope 1 and 2 GHG) by 2050. Concurrently, the Company released its 2021 ESG Report, which details AQN’s progress with respect to environmental, social and governance matters.

Algonquin Power & Utilities Corp. - Management Discussion & Analysis |

Impact of COVID-19 on Operating Results
For the three and twelve months e nded December 31, 2021, the Company’s operating results were not materially impacted by the COVID-19 pandemic. Approximately 60% of the Company’s workforce continues to work remotely and the Company continues to employ operational measures intended to protect the health and safety of its employees and customers. Over the coming months the Company is planning a return to base operations as the impacts of the pandemic further diminish.
The Company’s business, financial condition, cash flows and results of operations continue to be subject to actual and potential future impacts resulting from COVID-19, the full extent of which are not currently known. The extent of the future impact of the COVID-19 pandemic on the Company will depend on, among other things, the duration of the pandemic, the extent of the related public health measures taken in response to the pandemic and the Company’s efforts to mitigate the impact on its operations.
For a discussion of the risks the Company faces related to COVID-19 please refer to Enterprise Risk Management.
Outlook
The following discussion should be read in conjunction with the Forward-Looking Statements and Forward-Looking Information section in this MD&A. Actual results may differ materially from the estimates below. Accordingly, investors are cautioned not to place undue reliance on these estimates.
Estimated 2022 Adjusted Net Earnings Per Common Share
The Company estimates that its Adjusted Net Earnings per common share will be within a range of $0.72-$0.77 for the 2022 fiscal year, as compared to Adjusted Net Earnings per common share of $0.71 for the 2021 fiscal year (see Caution Concerning Non-G AAP Measures).
The Company’s 2022 Adjusted Net Earnings per common share estimate is based on the following key assumptions, as well as those set out under Forward-Looking Statements and Forward-Looking Information:
•normalized weather patterns in the geographical areas in which the Company operates or has projects;
•rate decisions in line with expectations;
•renewable energy production and realized pricing consistent with long-term averages;
•no impacts from COVID-19 on operations; and
•closing of the Kentucky Power Transaction in mid-2022.
Capital Investment Expectations
The Company anticipates making capital investments of between approximately $4.34 billion and $4.68 billion in 2022. See 2022 Capital Investments for a more detailed discussion of the Company’s 2022 capital investment estimates.
The Company has also announced an approximately $12.4 billion capital plan for the period from 2022 through the end of 2026, with approximately 70% expected to be invested by the Regulated Services Group and approximately 30% expected to be invested by the Renewable Energy Group (see Corporate Development).

Algonquin Power & Utilities Corp. - Management Discussion & Analysis |

2021 Fourth Quarter Results From Operations

Key Financial Information | Three months ended December 31
(all dollar amounts in $ millions except per share information) | 2021 |  | 2020
Revenue | $ | 594.8 |  |  | $ | 491.3 |
Net earnings attributable to shareholders | 175.6 |  |  | 504.2 |
Cash provided by operating activities | 126.5 |  |  | 174.0 |
Adjusted Net Earnings 1 | 136.3 |  |  | 127.0 |
Adjusted EBITDA 1 | 297.6 |  |  | 253.1 |
Adjusted Funds from Operations 1 | 221.2 |  |  | 179.3 |
Dividends declared to common shareholders | 115.5 |  |  | 93.1 |
Weighted average number of common shares outstanding | 653,728,621 |  |  | 597,165,849 |
Per share |  |  |
Basic net earnings | $ | 0.27 |  |  | $ | 0.84 |
Diluted net earnings | $ | 0.26 |  |  | $ | 0.83 |
Adjusted Net Earnings 1 | $ | 0.21 |  |  | $ | 0.21 |
Dividends declared to common shareholders | $ | 0.17 |  |  | $ | 0.16 |

1 | See Caution Concerning Non-GAAP Measures.

For the three months ended December 31, 2021, AQN experienced an average exchange rate of Canadian to U.S. dollars of approximately 0.7937 as compared to 0.7675 in the same period in 2020. As such, any quarter over quarter variance in revenue or expenses, in local currency, at any of AQN’s Canadian entities is affected by a change in the average exchange rate upon conversion to AQN’s reporting currency.
For the three months ended December 31, 2021, AQN reported total revenue of $594.8 million as compared to $491.3 million during the same period in 2020, an increase of $103.5 million or 21.1%. The major factors impacting AQN’s revenue in the three months ended December 31, 2021 as compared to the same period in 2020 are set out as follows:

Algonquin Power & Utilities Corp. - Management Discussion & Analysis | 13

(all dollar amounts in $ millions) | Three months ended December 31
Comparative Prior Period Revenue | $ | 491.3 |
REGULATED SERVICES GROUP |
Existing Facilities |
Electricity: Increase is primarily due to higher pass through commodity costs at the Empire Electric System, partially offset by higher operating costs at the CalPeco Electric System. | 0.4 |
Gas: Increase is primarily due to higher pass through commodity costs across all the Company’s gas systems and new connections at the New Brunswick Gas System. | 33.8 |
Water: Increase is due to higher consumption and organic growth at the Beardsley and Litchfield Park Water Systems, partially offset by lower pass though commodity costs at the Park Water System. | 0.8 |
Other: Decrease is primarily due to a reduction in projects at Ft. Benning. | (1.2) |
| 33.8 |
New Facilities |
Electricity: Acquisition of Liberty Group Limited (formerly Ascendant Group Limited (“Ascendant”)) (November 2020) and the Empire Wind Facilities (2021). | 50.1 |
Water: Acquisition of Empresa de Servicios Sanitarios de Los Lagos S.A.(“ESSAL”) (October 2020). | 2.6 |
| 52.7 |
Rate Reviews |
Electricity: Increase is primarily due to implementation of new rates at the CalPeco and Granite State Electric Systems. | 2.9 |
Gas: Increase is primarily due to implementation of new rates at the EnergyNorth and Midstates Gas Systems. | 0.5 |
Water: Increase is due to implementation of new rates at the Park Water and Apple Valley Water Systems. | 1.5 |
| 4.9 |
Estimated Impact of COVID-19 on comparative period results 1 | 0.7 |
RENEWABLE ENERGY GROUP |
Existing Facilities |
Hydro: Decrease is primarily due to lower production in the Ontario and Quebec Region, partially offset by favourable pricing in the Western Region. | (0.5) |
Wind Canada: Decrease is primarily due to lower production for the St. Damase, Morse and Amherst Wind Facilities. | (0.7) |
Wind U.S.: Decrease is primarily due to lower production for the Minonk, Shady Oaks, and Deerfield Wind Facilities along with unfavourable energy pricing, partially offset by higher renewable energy credit (“REC”) revenue across the U.S. Wind Facilities. | (1.9) |
Solar: Decrease is primarily due to lower REC revenue for the Great Bay I & II Solar Facilities, partially offset by favourable capacity rates and higher availability revenue as well as the receipt of an insurance payment for the Bakersfield I Solar Facility. | (0.6) |
Thermal: Increase is primarily due to favourable pricing at the Windsor Locks Thermal Facility, partially offset by unfavourable capacity pricing for the Sanger Thermal Facility. | 0.3 |
Other: Decrease is primarily due to higher administrative fees received in 2020 from joint venture construction projects. | (0.2) |
| (3.6) |
New Facilities |
Wind U.S.: Sugar Creek Wind Facility (full COD in November 2020) and Maverick Creek Wind Facility (full COD in April 2021). | 11.6 |
Solar: Altavista Solar Facility (full COD in June 2021) and Croton Solar Facility (full COD in December 2021). | 1.3 |
Other: Increase is due to Congestion Revenue Rights (“CRRs”) Revenue | 1.3 |
| 14.2 |
Foreign Exchange | 0.8 |
Current Period Revenue | $ | 594.8 |

1 | The impacts of COVID-19 were estimated by normalizing sales in both periods for changes in weather and attributing the remaining variances to COVID-19.

Algonquin Power & Utilities Corp. - Management Discussion & Analysis |

2021 Annual Results From Operations

Key Financial Information | Twelve months ended December 31
(all dollar amounts in $ millions except per share information) | 2021 |  | 2020 |  | 2019 |  |
Revenue | $ | 2,285.5 |  |  | $ | 1,677.0 |  |  | $ | 1,624.9 |  |  |
Net earnings attributable to shareholders | 264.9 |  |  | 782.5 |  |  | 530.9 |  |  |
Cash provided by operating activities | 157.5 |  |  | 505.2 |  |  | 611.3 |  |  |
Adjusted Net Earnings 1 | 449.6 |  |  | 365.8 |  |  | 321.3 |  |  |
Adjusted EBITDA 1 | 1,076.9 |  |  | 869.5 |  |  | 838.6 |  |  |
Adjusted Funds from Operations 1 | 757.9 |  |  | 600.2 |  |  | 566.2 |  |  |
Dividends declared to common shareholders | 423.0 |  |  | 344.4 |  |  | 277.8 |  |  |
Weighted average number of common shares outstanding | 622,347,677 |  |  | 559,633,275 |  |  | 499,910,876 |  |  |
Per share |  |  |  |  |  |  |
Basic net earnings | $ | 0.41 |  |  | $ | 1.38 |  |  | $ | 1.05 |  |  |
Diluted net earnings | $ | 0.41 |  |  | $ | 1.37 |  |  | $ | 1.04 |  |  |
Adjusted Net Earnings 1 | $ | 0.71 |  |  | $ | 0.64 |  |  | $ | 0.63 |  |  |
Dividends declared to common shareholders | $ | 0.67 |  |  | $ | 0.61 |  |  | $ | 0.55 |  |  |
Total assets | 16,785.8 |  |  | 13,224.1 |  |  | 10,920.8 |  |  |
Long term debt 2 | 6,211.7 |  |  | 4,538.8 |  |  | 3,932.2 |  |  |

1 | See Caution Concerning Non-GAAP Measures.
2 | Includes current and long-term portion of debt and convertible debentures per the annual consolidated financial statements

For the twelve months ended December 31, 2021, AQN experienced an average exchange rate of Canadian to U.S. dollars of approximately 0.7976 as compared to 0.7456 in the same period in 2020. As such, any year-over-year variance in revenue or expenses, in local currency, at any of AQN’s Canadian entities is affected by a change in the average exchange rate upon conversion to AQN’s reporting currency.
For the twelve months ended December 31, 2021, AQN reported total revenue of $2,285.5 million as compared to $1,677.0 million during the same period in 2020, an increase of $608.5 million or 36.3%. The major factors resulting in the increase in AQN revenue for the twelve months ended December 31, 2021 as compared to the same period in 2020 are as follows:

Algonquin Power & Utilities Corp. - Management Discussion & Analysis | 15

(all dollar amounts in $ millions) | Twelve months ended December 31
Comparative Prior Period Revenue | $ | 1,677.0 |
REGULATED SERVICES GROUP |
Existing Facilities |
Electricity: Increase is primarily due to higher consumption and pass through commodity costs at the Empire Electric System as a result of the Midwest Extreme Weather Event. | 177.3 |
Gas: Increase is primarily due to higher pass through commodity costs across all the Company's gas systems and new connections at the New Brunswick Gas System. | 60.5 |
Water: Increase is due to higher consumption and organic growth at the Litchfield Park Water, Beardsley and Midstates Water Systems. | 5.3 |
Other: Decrease is primarily due to a reduction in projects at Ft. Benning. | (0.7) |
| 242.4 |
New Facilities |
Electricity: Acquisition of Ascendant (November 2020) and the Empire Wind Facilities (2021). | 247.2 |
Water: Acquisition of ESSAL (October 2020). | 72.9 |
| 320.1 |
Rate Reviews |
Electricity: Increase is primarily due to implementation of new rates at the Granite State and CalPeco Electric Systems, partially offset by one-time revenues in the third quarter of 2020 from a rate increase with recoupment to the first quarter of 2019 at the CalPeco Electric System. | 2.9 |
Gas: Increase is primarily due to implementation of new rates at the EnergyNorth and Peach State Gas Systems. | 8.4 |
Water: Increase is due to implementation of new rates at the Park Water and Apple Valley Water Systems. | 3.0 |
| 14.3 |
Estimated Impact of COVID-19 on comparative period results 1 | 15.7 |
RENEWABLE ENERGY GROUP |
Existing Facilities |
Hydro:Decrease is primarily due to lower production in the Quebec Region, partially offset by favourable market pricing in the Western Region. | (0.4) |
Wind Canada: Decrease is primarily due to lower overall production partially offset by receipt of an insurance payment and higher availability income for the Amherst Wind Facility. | (1.8) |
Wind U.S.: Decrease is primarily due to the impacts from the Market Disruption Event at the Senate Wind Facility. | (54.4) |
Solar: Increase is primarily due to favourable capacity pricing and receipt of an insurance payment for the Great Bay I Solar Facility. | 1.0 |
Thermal: Increase is primarily due to higher production at the Sanger Thermal Facility as well as favourable pricing at the Windsor Locks Thermal Facility, partially offset by unfavourable capacity pricing for the Sanger Thermal Facility. | 5.6 |
Other: Decrease is primarily due to higher administrative fees received in 2020 from joint venture construction projects. | (1.4) |
| (51.4) |
New Facilities |
Wind U.S.: Sugar Creek Wind Facility (full COD in November 2020) and Maverick Creek Wind Facility (full COD in April 2021). | 51.1 |
Solar: Great Bay II Solar Facility (achieved COD in August 2020) and Altavista Solar Facility (full COD in June 2021). | 7.4 |
Other: Increase is due to CRRs from Texas Coastal Wind Facilities. | 2.0 |
| 60.5 |
Foreign Exchange | 6.9 |
Current Period Revenue | $ | 2,285.5 |

1 | The impacts of COVID-19 were estimated by normalizing sales in both periods for changes in weather and attributing the remaining variances to COVID-19.

Algonquin Power & Utilities Corp. - Management Discussion & Analysis |

2021 Net Earnings Summary
Net earnings attributable to shareholders for the three months ended December 31, 2021 totaled $175.6 million as compared to $504.2 million during the same period in 2020, a decrease of $328.6 million or 65.2%. Net earnings attributable to shareholders for the twelve months ended December 31, 2021 totaled $264.9 million as compared to $782.5 million during the same period in 2020, a decrease of $517.6 million or 66.1%. A summary of changes is shown below.

Change in Net Earnings | Three months ended |  | Twelve months ended |  |
| December 31 |  | December 31 |  |
(all dollar amounts in $ millions) | 2021 |  | 2021 |  |
Prior Period Balance | $ | 504.2 |  |  | $ | 782.5 |  |  |
Adjusted EBITDA | 44.5 |  |  | 207.4 |  |  |
Net earnings attributable to the non-controlling interest, exclusive of HLBV | 0.8 |  |  | (1.2) |  |  |
Income tax expense (recovery) | 49.3 |  |  | 108.0 |  |  |
Interest expense | (4.8) |  |  | (27.7) |  |  |
Other net losses | 4.7 |  |  | 38.4 |  |  |
Pension and post-employment non-service costs | (0.2) |  |  | (2.2) |  |  |
Change in value of investments carried at fair value | (403.0) |  |  | (682.1) |  |  |
Impacts from the Market Disruption Event on the Senate Wind Facility | — |  |  | (53.4) |  |  |
Costs related to tax equity financing | (0.5) |  |  | (5.7) |  |  |
Loss (gain) on derivative financial instruments | 1.1 |  |  | (2.7) |  |  |
Realized loss on energy derivative contracts | (0.2) |  |  | (1.0) |  |  |
Loss (gain) on foreign exchange | 2.5 |  |  | (6.5) |  |  |
Depreciation and amortization | (22.8) |  |  | (88.9) |  |  |
Current Period Balance | $ | 175.6 |  |  | $ | 264.9 |  |  |
Change in Net Earnings ($) | $ | (328.6) |  |  | $ | (517.6) |  |  |
Change in Net Earnings (%) | (65.2) | % |  | (66.1) | % |  |

During the three months ended December 31, 2021, cash provided by operating activities totaled $126.5 million as compared to $174.0 million during the same period in 2020, a decrease of $47.5 million. During the three months ended December 31, 2021, Adjusted Funds from Operations totaled $221.2 million as compared to Adjusted Funds from Operations of $179.3 million during the same period in 2020, an increase of $41.9 million (see Caution Concerning Non-GAAP Measures).
During the three months ended December 31, 2021, Adjusted EBITDA totaled $297.6 million as compared to $253.1 million during the same period in 2020, an increase of $44.5 million or 17.6%. A more detailed analysis of these factors is presented within the reconciliation of Adjusted EBITDA to net earnings set out below (see Caution Concerning Non-GAAP Measures).
During the twelve months ended December 31, 2021, cash provided by operating activities totaled $157.5 million as co mpared to $505.2 million during the same period in 2020. During the twelve months ended December 31, 2021, Adjusted Funds from Operations totaled $757.9 million as compared to $600.2 million the same period in 2020, an increase of $157.7 million (see Caution Concerning Non-GAAP Measures).
During the twelve months ended December 31, 2021, Adjusted EBITDA totaled $1,076.9 million as compared to $869.5 million during the same period in 2020, an increase of $207.4 million or 23.9%. A detailed analysis of this variance is presented within the reconciliation of Adjusted EBITDA to net earnings set out below under Non-GAAP Financial Measures.

Algonquin Power & Utilities Corp. - Management Discussion & Analysis | 17

2021 Adjusted EBITDA Summary
Adjusted EBITDA (see Caution Concerning Non-GAAP Measures) for the three months ended December 31, 2021 totaled $297.6 million as compared to $253.1 million during the same period in 2020, an increase of $44.5 million or 17.6%. Adjusted EBITDA for the twelve months ended December 31, 2021 totaled $1,076.9 million as compared to $869.5 million during the same period in 2020, an increase of $207.4 million or 23.9%. The breakdown of Adjusted EBITDA by the Company's main business units and a summary of changes are shown below.

Adjusted EBITDA by business units | Three months ended December 31 |  | Twelve months ended December 31
(all dollar amounts in $ millions) | 2021 |  | 2020 |  | 2021 |  | 2020
Divisional Operating Profit for Regulated Services Group 1 | $ | 191.4 |  |  | $ | 162.4 |  |  | $ | 758.8 |  |  | $ | 592.3 |
Divisional Operating Profit for Renewable Energy Group 1 | 123.9 |  |  | 97.9 |  |  | 389.6 |  |  | 335.7 |
Administrative Expenses | (17.8) |  |  | (12.6) |  |  | (66.7) |  |  | (63.1) |
Other Income & Expenses | 0.1 |  |  | 5.4 |  |  | (4.8) |  |  | 4.6 |
Total AQN Adjusted EBITDA | $ | 297.6 |  |  | $ | 253.1 |  |  | $ | 1,076.9 |  |  | $ | 869.5 |
Change in Adjusted EBITDA ($) | $ | 44.5 |  |  |  |  | $ | 207.4 |  |  |
Change in Adjusted EBITDA (%) | 17.6 | % |  |  |  | 23.9 | % |  |

1 | See Caution Concerning Non-GAAP Measures.

Change in Adjusted EBITDA | Three months ended December 31, 2021
(all dollar amounts in $ millions) | Regulated Services | Renewable Energy | Corporate | Total
Prior period balances | $ | 162.4 |  | $ | 97.9 |  | $ | (7.2) |  | $ | 253.1 |
Existing Facilities and Investments | (4.5) |  | (5.0) |  | (5.3) |  | (14.8) |
New Facilities and Investments | 27.9 |  | 29.7 |  | — |  | 57.6 |
Rate Reviews | 4.9 |  | — |  | — |  | 4.9 |
Estimated Impact of COVID-19 on comparative period results 1 | 0.7 |  | — |  | — |  | 0.7 |
Foreign Exchange Impact | — |  | 1.3 |  | — |  | 1.3 |
Administrative Expenses | — |  | — |  | (5.2) |  | (5.2) |
Total change during the period | $ | 29.0 |  | $ | 26.0 |  | $ | (10.5) |  | $ | 44.5 |
Current period balances | $ | 191.4 |  | $ | 123.9 |  | $ | (17.7) |  | $ | 297.6 |

Change in Adjusted EBITDA | Twelve months ended December 31, 2021
(all dollar amounts in $ millions) | Regulated Services | Renewable Energy | Corporate | Total
Prior period balances | $ | 592.3 |  | $ | 335.7 |  | $ | (58.5) |  | $ | 869.5 |
Existing Facilities and Investments | 2.4 |  | (7.8) |  | (9.4) |  | (14.8) |
New Facilities and Investments | 135.1 |  | 55.8 |  | — |  | 190.9 |
Rate Reviews | 14.3 |  | — |  | — |  | 14.3 |
Estimated Impact of COVID-19 on comparative period results 1 | 14.7 |  | — |  | — |  | 14.7 |
Foreign Exchange Impact | — |  | 5.9 |  | — |  | 5.9 |
Administrative Expenses | — |  | — |  | (3.6) |  | (3.6) |
Total change during the period | $ | 166.5 |  | $ | 53.9 |  | $ | (13.0) |  | $ | 207.4 |
Current period balances | $ | 758.8 |  | $ | 389.6 |  | $ | (71.5) |  | $ | 1,076.9 |

1 | The impacts of COVID-19 were estimated by normalizing sales in both periods for changes in weather and attributing the remaining variances to COVID-19.

Algonquin Power & Utilities Corp. - Management Discussion & Analysis | 18

REGULATED SERVICES GROUP
The Regulated Services Group operates rate-regulated utilities that as of December 31, 2021 provided distribution services to approximately 1,093,000 customer connections in the electric, natural gas, and water and wastewater sectors which is an increase of approximately 6,000 customer connections as compared to the prior year. With the acquisition of Liberty NY Water, the Regulated Services Group added an additional approximately 125,000 customer connections in the state of New York effective January 1, 2022. The Regulated Services Group now serves a total of approximately 1,218,000 customer connections.
The Regulated Services Group's strategy is to grow its business organically and through business development activities while using prudent acquisition criteria. The Regulated Services Group believes that its business results are maximized by building constructive regulatory and customer relationships, and enhancing customer connections in the communities in which it operates.

Utility System Type | As at December 31
2021 |  | 2020
(all dollar amounts in $ millions) | Assets | Net Utility Sales 1 | Total Customer Connections 2 |  | Assets | Net Utility Sales 1 | Total Customer Connections 2
Electricity | 4,721.6 |  | 707.6 |  | 307,000 |  |  | 3,271.8 |  | 548.8 |  | 306,000 |
Natural Gas | 1,573.4 |  | 331.7 |  | 373,000 |  |  | 1,470.1 |  | 310.4 |  | 371,000 |
Water and Wastewater | 842.5 |  | 222.3 |  | 413,000 |  |  | 827.8 |  | 142.5 |  | 410,000 |
Other | 256.7 |  | 53.4 |  |  |  | 187.8 |  | 19.1 |  |
Total | $ | 7,394.2 |  | $ | 1,315.0 |  | 1,093,000 |  |  | $ | 5,757.5 |  | $ | 1,020.8 |  | 1,087,000 |
Accumulated Deferred Income Taxes Liability | $ | 600.2 |  |  |  |  | $ | 520.1 |  |  |

1 | Net Utility Sales for the twelve months ended December 31, 2021 and 2020. See Caution Concerning Non-GAAP Measures.
2 | Total Customer Connections represents the sum of all active and vacant customer connections.

The Regulated Services Group aggregates the performance of its utility operations by utility system type – electricity, natural gas, and water and wastewater systems.
The electric distribution systems are comprised of regulated electrical distribution utility systems and served approximately 307,000 customer connections in the U.S. States of California, New Hampshire, Missouri, Kansas, Oklahoma and Arkansas and in Bermuda as at December 31, 2021.
The natural gas distribution systems are comprised of regulated natural gas distribution utility systems and served approximately 373,000 customer connections located in the U.S. States of New Hampshire, Illinois, Iowa, Missouri, Georgia, Massachusetts and New York and in the Canadian Province of New Brunswick as at December 31, 2021 .
The water and wastewater distribution systems are comprised of regulated water distribution and wastewater collection utility systems and served approximately 413,000 customer connections located in the U.S. States of Arkansas, Arizona, California, Illinois, Missouri and Texas and in Chile as at December 31, 2021. With the acquisition of Liberty NY Water the Regulated Services Group added an additional approximately 125,000 customer connections in the state of New York effective January 1, 2022.

Algonquin Power & Utilities Corp. - Management Discussion & Analysis | 19

2021 Annual Usage Results

Electric Distribution Systems | Three months ended December 31 |  | Twelve months ended December 31
| 2021 |  | 2020 |  | 2021 |  | 2020
Average Active Electric Customer Connections For The Period |  |  |  |  |  |  |
Residential | 261,100 |  |  | 260,300 |  |  | 260,600 |  |  | 259,600 |
Commercial and industrial | 42,300 |  |  | 42,300 |  |  | 42,100 |  |  | 42,200 |
Total Average Active Electric Customer Connections For The Period | 303,400 |  |  | 302,600 |  |  | 302,700 |  |  | 301,800 |
Customer Usage (GW-hrs) |  |  |  |  |  |  |
Residential | 581.7 |  |  | 638.0 |  |  | 2,769.7 |  |  | 2,485.9 |
Commercial and industrial | 899.3 |  |  | 896.3 |  |  | 3,701.1 |  |  | 3,406.0 |
Total Customer Usage (GW-hrs) | 1,481.0 |  |  | 1,534.3 |  |  | 6,470.8 |  |  | 5,891.9 |

For the three months ended December 31, 2021, the electric distribution systems' usage totaled 1,481.0 GW-hrs as compared to 1,534.3 GW-hrs for the same period in 2020, a decrease of 53.3 GW-hrs or 3.5%. The decrease in electricity consumption is primarily due to unfavorable weather at Empire Electric System in the fourth quarter of 2021.
For the twelve months ended December 31, 2021, the electric distribution systems' usage totaled 6,470.8 GW-hrs as compared to 5,891.9 GW-hrs for the same period in 2020, an increase of 578.9 GW-hrs or 9.8%. The increase in electricity consumption is primarily due to the acquisition of Ascendant in the fourth quarter of 2020, which contributed 522.6 GW-hrs.

Natural Gas Distribution Systems | Three months ended December 31 |  | Twelve months ended December 31
| 2021 |  | 2020 |  | 2021 |  | 2020
Average Active Natural Gas Customer Connections For The Period |  |  |  |  |  |  |
Residential | 318,000 |  |  | 316,700 |  |  | 318,600 |  |  | 317,100 |
Commercial and industrial | 38,100 |  |  | 37,300 |  |  | 38,100 |  |  | 37,700 |
Total Average Active Natural Gas Customer Connections For The Period | 356,100 |  |  | 354,000 |  |  | 356,700 |  |  | 354,800 |
Customer Usage (MMBTU) |  |  |  |  |  |  |
Residential | 5,750,000 |  |  | 6,022,000 |  |  | 20,703,000 |  |  | 21,214,000 |
Commercial and industrial | 5,077,000 |  |  | 5,157,000 |  |  | 18,696,000 |  |  | 18,362,000 |
Total Customer Usage (MMBTU) | 10,827,000 |  |  | 11,179,000 |  |  | 39,399,000 |  |  | 39,576,000 |

For the three months ended December 31, 2021, usage at the natural gas distribution systems totaled 10,827,000 MMBTU as compared to 11,179,000 MMBTU during the same period in 2020, a decrease of 352,000 MMBTU, or 3.1%. This was primarily due to warmer weather at the Mid-States, New York, Empire and New Brunswick Gas Systems.
For the twelve months ended December 31, 2021, usage at the natural gas distribution systems totaled 39,399,000 MMBTU as compared to 39,576,000 MMBTU during the same period in 2020, a decrease of 177,000 MMBTU, or 0.4%. This was primarily due to warmer weather at the New Brunswick, Energy North and Peach State Gas Systems.

Algonquin Power & Utilities Corp. - Management Discussion & Analysis | 20

Water and Wastewater Distribution Systems | Three months ended December 31 |  | Twelve months ended December 31
| 2021 |  | 2020 |  | 2021 |  | 2020
Average Active Customer Connections For The Period |  |  |  |  |  |  |
Wastewater customer connections | 47,000 |  |  | 45,900 |  |  | 46,500 |  |  | 45,800 |
Water distribution customer connections | 360,200 |  |  | 356,100 |  |  | 359,200 |  |  | 355,500 |
Total Average Active Customer Connections For The Period | 407,200 |  |  | 402,000 |  |  | 405,700 |  |  | 401,300 |
Gallons Provided (millions of gallons) |  |  |  |  |  |  |
Wastewater treated | 726 |  |  | 639 |  |  | 2,768 |  |  | 2,535 |
Water provided | 7,297 |  |  | 7,066 |  |  | 28,197 |  |  | 19,319 |
Total Gallons Provided (millions of gallons) | 8,023 |  |  | 7,705 |  |  | 30,965 |  |  | 21,854 |

For the three months ended December 31, 2021, the water and wastewater distribution systems provided approximately 7,297 million gallons of water to customers and treated approximately 726 million gallons of wastewater. This is compared to 7,066 million gallons of water provided and 639 million gallons of wastewater treated during the same period in 2020, an increase in total gallons provided of 319 million, or 4.1%. This is primarily due to increased water consumption at ESSAL of 236 million gallons or 8.8% driven by commercial customers who were not operating during the fourth quarter of 2020 due to COVID-19 restrictions.
For the twelve months ended December 31, 2021, the water and wastewater distribution systems provided approximately 28,197 gallons of water to customers and treated approximately 2,768 gallons of wastewater. This is compared to 19,319 gallons of water provided and 2,535 gallons of wastewater treated during the same period in 2020, an increase in total gallons provided of 9,111 million, or 41.7%. The increase is primarily due to the acquisition of ESSAL in the fourth quarter of 2020, which contributed 11,212 million gallons of water provided.

Algonquin Power & Utilities Corp. - Management Discussion & Analysis |

2021 Regulated Services Group Operating Results

| Three months ended December 31 |  | Twelve months ended December 31
(all dollar amounts in $ millions) | 2021 |  | 2020 |  | 2021 |  | 2020
Revenue |  |  |  |  |  |  |
Regulated electricity distribution | $ | 261.3 |  |  | $ | 213.3 |  |  | $ | 1,183.4 |  |  | $ | 776.3 |
Less: Regulated electricity purchased | (93.0) |  |  | (69.4) |  |  | (475.8) |  |  | (227.5) |
Net Utility Sales - electricity 1 | 168.3 |  |  | 143.9 |  |  | 707.6 |  |  | 548.8 |
Regulated gas distribution | 172.0 |  |  | 137.0 |  |  | 525.9 |  |  | 454.7 |
Less: Regulated gas purchased | (80.2) |  |  | (48.1) |  |  | (194.2) |  |  | (144.3) |
Net Utility Sales - natural gas 1 | 91.8 |  |  | 88.9 |  |  | 331.7 |  |  | 310.4 |
Regulated water reclamation and distribution | 58.3 |  |  | 52.9 |  |  | 234.9 |  |  | 155.0 |
Less: Regulated water purchased | (2.6) |  |  | (3.3) |  |  | (12.6) |  |  | (12.5) |
Net Utility Sales - water reclamation and distribution 1 | 55.7 |  |  | 49.6 |  |  | 222.3 |  |  | 142.5 |
Other revenue 2 | 13.4 |  |  | 9.7 |  |  | 53.4 |  |  | 19.1 |
Net Utility Sales 3 | 329.2 |  |  | 292.1 |  |  | 1,315.0 |  |  | 1,020.8 |
Operating expenses | (149.0) |  |  | (133.1) |  |  | (597.9) |  |  | (442.9) |
Other income | 3.9 |  |  | 1.8 |  |  | 18.3 |  |  | 7.8 |
HLBV 4 | 7.3 |  |  | 1.6 |  |  | 23.4 |  |  | 6.6 |
Divisional Operating Profit 1,5,6 | $ | 191.4 |  |  | $ | 162.4 |  |  | $ | 758.8 |  |  | $ | 592.3 |

1 | See Caution Concerning Non-GAAP Measures.
2 | See Note 21 in the annual consolidated financial statements.
3 | This table contains a reconciliation of Net Utility Sales to revenue. The relevant sections of the table are derived from and should be read in conj unction with the consolidated statement of operations and Note 21 in the annual consolidated financial statements, “Segmented Information”. This supplementary disclosure is intended to more fully explain disclosures related to Net Utility Sales and provides additional information related to the operating performance of the Regulated Services Group. Investors are cautioned that Net Utility Sales should not be construed as an alternative to revenue.
4 | HLBV income represents the value of net tax attributes monetized by the Regulated Services Group in the period at the Luning and Turquoise Solar Facilities and the Empire Wind Facilities.
5 | This table contains a reconciliation of Divisional Operating Profit to revenue. The relevant sections of the table are derived from and should be read in conj unction with the consolidated statement of operations and Note 21 in the annual consolidated financial statements, “Segmented Information”. This supplementary disclosure is intended to more fully explain disclosures related to Divisional Operating Profit and provides additional information related to the operating performance of the Regulated Services Group. Investors are cautioned that Divisional Operating Profit should not be construed as an alternative to revenue.
6 | Certain prior year items have been reclassified to conform with current year presentation.

Algonquin Power & Utilities Corp. - Management Discussion & Analysis | 22

2021 Fourth Quarter Operating Results
For the three months ended December 31, 2021, the Regulated Services Group reported revenue of $491.6 million (i.e., $261.3 million of regulated electricity distribution, $172.0 million of regulated gas distribution and $58.3 million of regulated water reclamation and distribution) as compared to revenue of $403.2 million in the comparable period in the prior year (i.e., $213.3 million of regulated electricity distribution, $137.0 million of regulated gas distribution and $52.9 million of regulated water reclamation and distribution).
For the three months ended December 31, 2021, the Regulated Services Group reported a Divisional Operating Profit (excluding corporate administration expenses) of $191.4 million as compared to $162.4 million for the comparable period in the prior year (see Caution Concerning Non-GAAP Measures).
Highlights of the changes are summarized in the following table:

(all dollar amounts in $ millions) | Three months ended December 31
Prior Period Divisional Operating Profit 1 | $ | 162.4 |
Existing Facilities |
Electricity: Decrease is primarily due to lower consumption driven by milder temperatures and higher non-pass through fuel costs at the Empire Electric System, as well as higher operating costs at the Granite State and CalPeco Electric Systems. | (10.9) |
Gas: Increase is primarily due to higher Gas System Enhancement Plan (GSEP) mechanism revenue at the New England Gas System, increased revenues as a result of the implementation of a decoupling mechanism in the fourth quarter of 2021 and lower operating costs at the Peach State Gas System, and new connections at the New Brunswick Gas System. | 3.2 |
Water: Increase is primarily due to lower operating costs at the Park Water System. | 1.4 |
Other: Increase is due to recoverable carrying costs related to the Midwest Extreme Weather Event. | 1.8 |
| (4.5) |
New Facilities |
Electricity: Acquisition of Ascendant (November 2020) and the Empire Wind Facilities (2021). | 25.4 |
Water: Acquisition of ESSAL (October 2020). | 2.5 |
| 27.9 |
Rate Reviews |
Electricity: Increase is primarily due to implementation of new rates at the CalPeco and Granite State Electric Systems. | 2.9 |
Gas: Increase is primarily due to implementation of new rates at the EnergyNorth and Midstates Gas Systems. | 0.5 |
Water: Increase is due to the implementation of new rates at the Park Water and Apple Valley Water Systems. | 1.5 |
| 4.9 |
Estimated Impact of COVID-19 on comparative period results 2 | 0.7 |
Current Period Divisional Operating Profit 1 | $ | 191.4 |

1 | See Caution Concerning Non-GAAP Measures.
2 | The impacts of COVID-19 were estimated by normalizing sales in both periods for changes in weather and attributing the remaining variances to COVID-19.

Algonquin Power & Utilities Corp. - Management Discussion & Analysis | 23

2021 Annual Operating Results
For the twelve months ended December 31, 2021, the Regulated Services Group reported revenue of $1,944.2 million (i.e., $1,183.4 million of regulated electricity distribution, $525.9 million of regulated gas distribution and $234.9 million of regulated water reclamation and distribution) as compared to revenue of $1,386.0 million in the prior year (i.e., $776.3 million of regulated electricity distribution, $454.7 million of regulated gas distribution and $155.0 million of regulated water reclamation and distribution).
For the twelve months ended December 31, 2021, the Regulated Services Group reported an Divisional Operating Profit (excluding corporate administration expenses) of $758.8 million as compared to $592.3 million in the prior year (see Caution Concerning Non-GAAP Measures).
Highlights of the changes are summarized in the following table:

(all dollar amounts in $ millions) | Twelve months ended December 31
Prior Period Divisional Operating Profit 1 | $ | 592.3 |
Existing Facilities |
Electricity: Decrease is primarily due to lower consumption at the Empire Electric System driven by milder temperatures as well as higher operating costs at the Empire, Granite State and CalPeco Electric Systems. | (22.9) |
Gas: Increase is primarily due to higher Gas System Enhancement Plan (GSEP) mechanism revenue at the New England Gas System, new connections at the New Brunswick Gas System, favourable property tax adjustments at the EnergyNorth Gas System and higher pass through commodity costs at the Midstates Gas System. | 12.9 |
Water: Increase is primarily due to higher consumption and growth in connections at the Beardsley and Litchfield Park Water Systems as well as lower operating costs at the Park Water System. | 3.3 |
Other: Increase is primarily due to recoverable carrying costs related to the Midwest Extreme Weather Event and higher earnings from the San Antonio Water System investment, partially offset by reduction in projects at Ft. Benning. | 9.1 |
| 2.4 |
New Facilities |
Electricity: Acquisition of Ascendant (November 2020) and the Empire Wind Facilities (2021). | 104.4 |
Water: Acquisition of ESSAL (October 2020). | 30.7 |
| 135.1 |
Rate Reviews |
Electricity: Increase is primarily due to implementation of new rates at the Granite State and CalPeco Electric Systems, partially offset by one-time revenues in the third quarter of 2020 from a rate increase with recoupment to the first quarter of 2019 at the CalPeco Electric System. | 2.9 |
Gas: Increase is primarily due to implementation of new rates at the EnergyNorth and Peach State Gas Systems. | 8.4 |
Water: Increase is due to implementation of new rates at the Park Water and Apple Valley Water Systems. | 3.0 |
| 14.3 |
Estimated Impact of COVID-19 on comparative period results 2 | 14.7 |
Current Period Divisional Operating Profit 1 | $ | 758.8 |

1 | See Caution Concerning Non-GAAP Measures.
2 | The impacts of COVID-19 were estimated by normalizing sales in both periods for changes in weather and attributing the remaining variances to COVID-19.

Algonquin Power & Utilities Corp. - Management Discussion & Analysis | 24

Regulatory Proceedings
The following table summarizes the major regulatory proceedings currently underway or completed within 2021 within the Regulated Services Group 1.

Utility | Jurisdiction | Regulatory Proceeding Type | Rate Request (millions) | Current Status
Completed Rate Reviews |  |  |  |
BELCO | Bermuda | GRC | $5.9 | On November 17, 2020, filed its initial revenue allowance application and, in consultation with the Regulatory Authority of Bermuda ("RA"), provided updates to this filing on January 18, 2021 and February 25, 2021. On April 27, 2021, BELCO submitted a revised application to establish an overall revenue requirement of $215.5 million for 2021, increasing authorized revenues by $5.9 million. Additionally, BELCO offered to defer a portion of its revenues from both 2021 and 2022, to be collected over a period of 10 years, beginning in 2022, while maintaining its weighted average cost of capital ("WACC") at 8%. On May 7, 2021, the RA issued a final decision, approving a WACC of 7.5% and authorizing $211.4 million in revenue with $13.4 million in deferred earned revenue to be collected over 5 years at a minimum WACC of 7.5%. The revenue requirement included $71.2 million for fuel and purchased power costs for the period from January 1, 2021 through December 31, 2021. The new rates were effective June 1, 2021.
EnergyNorth Gas System | New Hampshire | GRC | $13.5 | The New Hampshire Public Utilities Commission (“NHPUC”) issued an order approving a permanent increase of $6.3 million in annual distribution revenues for EnergyNorth effective August 1, 2021. The NHPUC approved the Company’s right to request two step increases for 2020 and 2021 projects, capped at $4.0 million and $3.2 million respectively, which will be addressed in separate proceedings. The Company’s request for the $4.0 million step increase for 2020 projects is pending. The Company expects to make a filing for approval of the second step increase in the second quarter of 2022. The NHPUC also approved a property tax reconciliation mechanism. Recovery of Granite Bridge feasibility costs, which were included in a supplemental filing in November 2020, were separately litigated in hearings in June 2021. An order denying recovery of litigated Granite Bridge costs was received in October 2021 and was based on a legal interpretation of a New Hampshire statute that prohibits recovery of construction work in progress. The Company's request for rehearing was denied on February 17, 2022; the Company intends to appeal the decision to the New Hampshire Supreme Court
ESSAL | Chile | VII Tariff Process | N/A | ESSAL’s VII tariff process began in April 2020 to set rates for the five-year period from September 2021 to September 2026. On July 30, 2021, ESSAL and the Chilean water sector regulator the Superintendencia de Servicios Sanitarios reached a settlement of ESSAL’s VII Tariff Process, setting ESSAL’s base tariffs from September 2021 to September 2026. On balance of settlement terms, ESSAL’s 2022 revenues are projected to increase by approximately $2.7 million. The new tariffs are expected to go into effect in the first quarter of 2022 upon publication of the Tariff Decree and Order by the Comptroller General.

Algonquin Power & Utilities Corp. - Management Discussion & Analysis | 25

Utility | Jurisdiction | Regulatory Proceeding Type | Rate Request (millions) | Current Status
Various | Various | GRC | $1.5 | Approval of approximately $0.8 million in rate increases for a natural gas and wastewater utility.
Pending Rate Reviews |  |  |  |
Empire | Missouri | GRC | $79.9 | On May 28, 2021, Empire filed a rate review based on a 12 month historical test year ending September 30, 2020, with an update period through June 30, 2021, seeking to recover an annual revenue deficiency of $50.0 million, or a 7.61% increase in total base rate operating revenue, based on a rate base of $2.6 billion, which includes the recently completed Empire Wind Facilities, and $29.9 million in costs associated with the impact of the Midwest Extreme Weather Event. On February 4, 2022, Empire filed the last of four stipulation agreements resolving all issues, except rate design which was litigated on February 10, 2022 . If approved by the Missouri Public Service Commission (“MPSC”), Empire would increase its annual revenues in Missouri by $39.5 million in May 2022. On January 19, 2022, Empire filed a petition for securitization of the costs associated with the impact of the Midwest Extreme Weather Event. An order on the securitization is expected in July/August 2022.
Empire | Kansas | GRC | $4.5 | On May 27, 2021, submitted an abbreviated rate review seeking to recover a revenue deficiency of $4.5 million associated with the addition of the Empire Wind Facilities, the retirement of Asbury and non-growth related plant investments since the 2019 rate review. On September 15, 2021, filed an updated revenue requirement reflecting near final wind costs. A virtual public hearing was held in November 2021.
CalPeco Electric System | California | GRC | $35.7 | On May 28, 2021, filed an application requesting a revenue increase of $35.7 million for 2022 based on an ROE of 10.5% and on a 54% equity capital structure.
Apple Valley Ranchos Water System | California | GRC | $2.9 | On July 2, 2021, filed an application requesting revenue increases of $2.9 million for 2022, $2.1 million for 2023, and $2.3 million for 2024 based on an ROE of 9.4% and on a 57% equity capital structure. CPUC Public Advocates Office issued its report in January 2022. Rebuttal testimony was filed in February 2022.
Park Water System | California | GRC | $5.5 | On July 2, 2021, filed an application requesting revenue increases of $5.5 million for 2022, $1.8 million for 2023, and $1.8 million for 2024 based on an ROE of 9.4% and on a 57% equity capital structure. CPUC Public Advocates Office issued its report in January 2022. Rebuttal testimony was filed in February 2022.
Empire District Gas Company | Missouri | GRC | $1.4 | On August 23, 2021, filed an application requesting a revenue increase of $1.4 million based on an ROE of 10% and on a 52% equity capital structure. In January 2022, MPSC Staff filed its testimony, recommending a $1.0 million revenue increase based on an ROE of 9.5%.

Algonquin Power & Utilities Corp. - Management Discussion & Analysis |

Utility | Jurisdiction | Regulatory Proceeding Type | Rate Request (millions) | Current Status
BELCO | Bermuda | GRC | $34.8 | On September 30, 2021, filed its revenue allowance application in which it requested a $34.8 million increase for 2022 and a $6.1 million increase for 2023.
New Brunswick Gas | Canada | GRC | -$3.9 | On November 22, 2021, filed its 2022 general rate application for a revenue decrease based on the EUB’s recent decision authorizing a capital structure of 45% equity and an ROE of 8.5%. A hearing is scheduled for March 28-31, 2022.
St. Lawrence Gas | New York | GRC | $4.1 | On November 24, 2021, filed an application requesting a revenue increase of $3.4 million based on an ROE of 10.5% and a capital structure of 50% equity. On January 31, 2022, filed a supplemental filing to update the requested revenue increase to $4.1 million.
Various | Various | Various | $0.1 | Other pending rate review requests across two wastewater utilities.

1 | All rate requests do not include step-up adjustments

Regulatory Proceedings related to the Midwest Extreme Weather Event
The Midwest Extreme Weather Event resulted in an increase in demand for natural gas used by Empire for the generation of electricity. Empire’s Missouri retail jurisdiction incurred approximately $205 million in extraordinary fuel and purchased power costs, carrying charges, and legal costs, including Southwest Power Pool ("SPP") market charges, related to the event. The amount of purchased power costs incurred by Empire is subject to resettlement activity and further review by SPP. This review and any subsequent resettlement activity could result in increases or decreases to the final amount of purchased power costs incurred by Empire. and these changes could be material. As of December 31, 2021, Empire has deferred substantially all of the fuel and purchased power costs related to the Midwest Extreme Weather Event to a regulatory asset. 95% of extraordinary fuel and purchased power costs are deferred pursuant to a fuel adjustment clause proceeding. The remaining 5% of the extraordinary fuel and purchased power costs, plus carrying charges and legal fees, are being deferred pursuant to an Accounting Authority Order ("AAO") request. While Empire currently expects to recover substantially all of the increased fuel and purchased power costs related to the Midwest Extreme Weather Event from customers, the timing of the cost recovery is expected to be be delayed or spread over a longer than typical recovery timeframe to help moderate monthly customer bill impacts given the extraordinary nature of the Midwest Extreme Weather Event.
When Empire filed its most recent Missouri rate case (ER-2021-0312) in May 2021, costs related to the Midwest Extreme Weather Event were included. In July 2021, Missouri House Bill 734 was signed into law, creating an option for utilities to finance the recovery of extraordinary weather event costs. When it filed its surrebuttal testimony in ER-2021-0312 in January 2022, Empire removed all costs related to the Midwest Extreme Weather Event from its rate request. Pursuant to House Bill 734, Empire filed a Petition for Financing Order for authorization of the issuance of securitized utility tariff bonds regarding 100% of the extraordinary costs incurred during the Midwest Extreme Winter Weather Event. A decision by the MPSC regarding Empire’s securitization request is required by August 22, 2022.
Regulatory Proceedings related to the retirement of Asbury
In the course of completing its 2017 and 2019 Integrated Resource Plans (“IRPs”), Empire analyzed the effects of retiring Asbury, a coal-fired generation unit that was constructed in 1970. In the course of the 2019 IRP, Empire determined that retiring the plant would generate $93.0 million in customer savings in the 20 years following the unit’s decommissioning. Asbury was retired on March 1, 2020. On July 23, 2020, the MPSC issued an AAO that directed Empire to establish regulatory asset and liability accounts, beginning January 1, 2020, to reflect impact of the closure of Asbury on operating and capital expenses in Missouri.
When Empire filed its most recent Missouri rate case (ER-2021-0312) in May 2021, its Asbury related revenues and expenses, along with the balance of the AAO, were included in the application. In July 2021, Missouri House Bill 734 created an option for utilities to finance the recovery of costs related to the retirement of obsolescent generation infrastructure, including recovery of undepreciated ratebase balances and financing costs, through securitized utility tariff bonds.

Algonquin Power & Utilities Corp. - Management Discussion & Analysis |

When it filed its surrebuttal testimony in ER-2021-0312 in January 2022, Empire removed all the balances associated with Asbury from its rate request, including the undepreciated balance on the asset and other Asbury-related balances, resulting in total amounts to be securitized of approximately $90.0 million. Subsequently, on January 20, 2022, Empire filed with the MPSC notice of its intent to file a petition and request the securitization of its Asbury related balances. The securitization legislation requires that the petition be filed no less than 60 days after the notice has been filed. As such,it is expected that Empire will submit its securitization petition in March 2022.
As of March 1, 2022, Empire has also filed rate cases that include requests for recovery of costs related to Asbury in Kansas and Oklahoma. Both cases are pending.
Regulatory Proceedings related to Acquisitions:
Kentucky Power
On October 26, 2021, Liberty Utilities entered into an agreement with American Electric Power Company, Inc. and AEP Transmission Company, LLC to acquire Kentucky Power and Kentucky TransCo.
On January 4, 2022, Liberty Utilities and Kentucky Power jointly filed for the approval of the Kentucky Power Transaction at the KPSC. By statute, the KPSC must issue an order on the application within 120 days, and therefore, the KPSC has issued a procedural schedule which calls for hearings to occur on March 28, 2022, and an order on the application is expected on or before May 4, 2022. In addition to the approval of the KPSC, closing of the Kentucky Power Transaction is subject to receipt of certain other regulatory approvals, including the approval of FERC and the approval of KPSC, FERC and the Public Service Commission of West Virginia with respect to the termination and replacement of the existing operating agreement for the Mitchell Plant.

Algonquin Power & Utilities Corp. - Management Discussion & Analysis |

RENEWABLE ENERGY GROUP

2021 Electricity Generation Performance
| Long Term Average Resource |  | Three months ended December 31 |  | Long Term Average Resource |  | Twelve months ended December 31
(Performance in GW-hrs sold) |  | 2021 |  | 2020 |  |  | 2021 |  | 2020
Hydro Facilities: |  |  |  |  |  |  |  |  |  |  |
Maritime Region | 37.6 |  |  | 36.7 |  |  | 41.8 |  |  | 148.2 |  |  | 124.2 |  |  | 119.4 |
Quebec Region | 72.6 |  |  | 74.4 |  |  | 80.6 |  |  | 273.3 |  |  | 266.6 |  |  | 281.7 |
Ontario Region | 26.2 |  |  | 21.8 |  |  | 27.7 |  |  | 120.4 |  |  | 91.2 |  |  | 104.1 |
Western Region | 12.6 |  |  | 9.1 |  |  | 7.0 |  |  | 65.0 |  |  | 49.9 |  |  | 63.2 |
| 149.0 |  |  | 142.0 |  |  | 157.1 |  |  | 606.9 |  |  | 531.9 |  |  | 568.4 |
Canadian Wind Facilities: |  |  |  |  |  |  |  |  |  |  |
St. Damase | 22.7 |  |  | 18.3 |  |  | 21.9 |  |  | 76.9 |  |  | 70.8 |  |  | 76.9 |
St. Leon | 121.4 |  |  | 127.5 |  |  | 119.4 |  |  | 430.2 |  |  | 422.5 |  |  | 427.5 |
Red Lily 1 | 24.1 |  |  | 26.3 |  |  | 25.6 |  |  | 88.5 |  |  | 91.2 |  |  | 92.1 |
Morse | 30.5 |  |  | 31.0 |  |  | 31.6 |  |  | 108.8 |  |  | 107.2 |  |  | 111.2 |
Amherst | 67.9 |  |  | 62.8 |  |  | 70.6 |  |  | 229.8 |  |  | 198.4 |  |  | 216.3 |
| 266.6 |  |  | 265.9 |  |  | 269.1 |  |  | 934.2 |  |  | 890.1 |  |  | 924.0 |
U.S. Wind Facilities: |  |  |  |  |  |  |  |  |  |  |
Sandy Ridge | 43.6 |  |  | 41.7 |  |  | 41.1 |  |  | 158.3 |  |  | 134.8 |  |  | 143.8 |
Minonk | 189.8 |  |  | 194.7 |  |  | 195.1 |  |  | 673.7 |  |  | 622.1 |  |  | 618.5 |
Senate | 140.0 |  |  | 144.1 |  |  | 142.2 |  |  | 520.4 |  |  | 480.5 |  |  | 501.8 |
Shady Oaks | 100.5 |  |  | 100.7 |  |  | 102.9 |  |  | 355.6 |  |  | 319.2 |  |  | 319.6 |
Odell | 238.0 |  |  | 214.7 |  |  | 212.8 |  |  | 831.8 |  |  | 720.3 |  |  | 795.3 |
Deerfield | 167.9 |  |  | 150.8 |  |  | 174.2 |  |  | 546.0 |  |  | 515.9 |  |  | 541.0 |
Sugar Creek 2 | 212.6 |  |  | 189.4 |  |  | 62.8 |  |  | 489.4 |  |  | 426.4 |  |  | 62.8 |
Maverick Creek 3 | 480.2 |  |  | 483.0 |  |  | 137.8 |  |  | 1,735.6 |  |  | 1,519.2 |  |  | 137.8 |
| 1,572.6 |  |  | 1,519.1 |  |  | 1,068.9 |  |  | 5,310.8 |  |  | 4,738.4 |  |  | 3,120.6 |
Solar Facilities: |  |  |  |  |  |  |  |  |  |  |
Cornwall | 2.2 |  |  | 2.1 |  |  | 1.9 |  |  | 14.7 |  |  | 14.6 |  |  | 14.7 |
Bakersfield | 13.0 |  |  | 9.1 |  |  | 11.0 |  |  | 77.2 |  |  | 66.0 |  |  | 64.5 |
Great Bay 4 | 37.6 |  |  | 40.8 |  |  | 40.3 |  |  | 205.7 |  |  | 208.4 |  |  | 171.6 |
Altavista 5 | 31.4 |  |  | 32.1 |  |  | — |  |  | 139.6 |  |  | 127.5 |  |  | — |
Croton 6 | 0.2 |  |  | 0.2 |  |  | — |  |  | 0.2 |  |  | 0.2 |  |  | — |
| 84.4 |  |  | 84.3 |  |  | 53.2 |  |  | 437.4 |  |  | 416.7 |  |  | 250.8 |
Renewable Energy Performance | 2,072.6 |  |  | 2,011.3 |  |  | 1,548.3 |  |  | 7,289.3 |  |  | 6,577.1 |  |  | 4,863.8 |
Thermal Facilities: |  |  |  |  |  |  |  |  |  |  |
Windsor Locks | N/A 7 |  | 31.0 |  |  | 34.0 |  |  | N/A 7 |  | 128.8 |  |  | 122.1 |
Sanger | N/A 7 |  | 34.5 |  |  | 25.5 |  |  | N/A 7 |  | 145.4 |  |  | 59.6 |
|  |  | 65.5 |  |  | 59.5 |  |  |  |  | 274.2 |  |  | 181.7 |
Total Performance |  |  | 2,076.8 |  |  | 1,607.8 |  |  |  |  | 6,851.3 |  |  | 5,045.5 |

1 | AQN owns a 75% equity interest but accounts for the facility using the equity method. Figures show full energy produced by the facility.
2 | Achieved COD on November 9, 2020. As a result of a blade manufacturing error 26 of 40 turbines were initially shut down. All impacted turbines were back in service as of September 29, 2021. Long-term average resources (“LTAR”) for the twelve months ended December 31, 2021 have been adjusted to reflect turbines that were operational during these periods.

Algonquin Power & Utilities Corp. - Management Discussion & Analysis | 29

3 | Achieved partial completion on November 6, 2020 and COD on April 21, 2021. As a result of a blade manufacturing error 26 of 73 turbines were initially shut down. All impacted turbines were back in service as of June 7, 2021. LTARs for the twelve months ended December 31, 2021 have been adjusted to reflect turbines that were operational during these periods.
4 | The Great Bay II Solar Facility achieved partial completion on April 15, 2020 and COD on August 13, 2020.
5 | Achieved partial completion on March 8, 2021 and COD on June 1, 2021. Prior to April 9, 2021, AQN owned a 50% equity interest in the facility. On April 9, 2021, AQN acquired the remaining 50% equity interest that it did not previously own. Figures show full energy produced by the facility.
6 | The Croton Solar Facility achieved COD on December 8, 2021. The LTARs noted above represents all production from the date of COD.
7 | Natural gas fired co-generation facility.

2021 Fourth Quarter Renewable Energy Group Performance
For the three months ended December 31, 2021, the Renewable Energy Group generated 2,076.8 GW-hrs of electricity as compared to 1,607.8 GW-hrs during the same period of 2020.
For the three months ended December 31, 2021, the hydro facilities generated 142.0 GW-hrs of electricity as compared to 157.1 GW-hrs produced in the same period in 2020, a decrease of 9.6%. Electricity generated represented 95.3% of LTAR as compared to 105.4% during the same period in 2020. During the quarter, all regions except the Quebec Region were below their respective LTAR.
For the three months ended December 31, 2021, the wind facilities produced 1,785.0 GW-hrs of electricity as compared to 1,338.0 GW-hrs produced in the same period in 2020, an increase of 33.4%. The increase in production is primarily due to the addition of the Sugar Creek Wind Facility which achieved COD on November 9, 2020, and the Maverick Creek Wind Facility which achieved COD on April 21, 2021. Excluding the new facilities, production was 2.2% below the same period last year. The wind facilities, including new facilities, generated electricity equal to 97.1% of LTAR as compared to 85.5% during the same period in 2020
For the three months ended December 31, 2021, the solar facilities generated 84.3 GW-hrs of electricity as compared to 53.2 GW-hrs of electricity in the same period in 2020, an increase of 58.5%. The increase in production is primarily due to the Altavista Solar Facility which achieved partial completion on March 8, 2021 and COD on June 1, 2021. In addition, the Croton Solar Facility achieved COD on December 8, 2021. Excluding the new facilities, production was 2.3% below the same period last year. The solar facilities generated electricity equal to 99.9% of LTAR as compared to 100.8% in the same period in 2020.
For the three months ended December 31, 2021, the thermal facilities generated 65.5 GW-hrs of electricity as compared to 59.5 GW-hrs of electricity during the same period in 2020. During the same period, the Windsor Locks Thermal Facility generated 132.1 billion lbs of steam as compared to 140.8 billion lbs of steam during the same period in 2020.
2021 Annual Renewable Energy Group Performance
For the twelve months ended December 31, 2021, the Renewable Energy Group generated 6,851.3 GW-hrs of electricity as compared to 5,045.5 GW-hrs during the same period in 2020.
For the twelve months ended December 31, 2021, the hydro facilities generated 531.9 GW-hrs of electricity as compared to 568.4 GW-hrs produced in the same period in 2020, a decrease of 6.4%. Electricity generated represented 87.6% of LTAR as compared to 93.7% during the same period in 2020.
For the twelve months ended December 31, 2021, the wind facilities produced 5,628.5 GW-hrs of electricity as compared to 4,044.6 GW-hrs produced in the same period in 2020, an increase of 39.2%. The increase in production is primarily due to the addition of the Sugar Creek Wind Facility which achieved COD on November 9, 2020, and the Maverick Creek Wind Facility which achieved COD on April 21, 2021. Excluding the new facilities, production was 4.2% below the same period last year. The wind facilities generated electricity equal to 90.1% of LTAR as compared to 91.1% during the same period in 2020.
For the twelve months ended December 31, 2021, the solar facilities generated 416.7 GW-hrs of electricity as compared to 250.8 GW-hrs of electricity produced in the same period in 2020, an increase of 66.1%. The increase in production is primarily due to the addition of the Great Bay II Solar Facility which achieved partial completion on April 15, 2020 and COD on August 13, 2020, and the Altavista Solar Facility which achieved partial completion on March 8, 2021 and COD on June 1, 2021. In addition, the Croton Solar Facility achieved COD on December 8, 2021. Excluding the new facilities, production was 1.4% above the same period last year. The solar facilities generated electricity equal to 95.3% of LTAR as compared to 88.9% in the same period in 2020.

Algonquin Power & Utilities Corp. - Management Discussion & Analysis | 30

For the twelve months ended December 31, 2021, the thermal facilities generated 274.2 GW-hrs of electricity as compared to 181.7 GW-hrs of electricity during the same period in 2020. For the twelve months ended December 31, 2021, the Windsor Locks Thermal Facility generated 507.0 billion lbs of steam as compared to 571.2 billion lbs of steam during the same period in 2020.

2021 Renewable Energy Group Operating Results
| Three months ended December 31 |  | Twelve months ended December 31
(all dollar amounts in $ millions) | 2021 |  | 2020 |  | 2021 |  | 2020
Revenue 1 |  |  |  |  |  |  |
Hydro | $ | 11.8 |  |  | $ | 10.8 |  |  | $ | 43.4 |  |  | $ | 39.8 |
Wind | 59.3 |  |  | 51.0 |  |  | 161.2 |  |  | 165.9 |
Solar | 5.6 |  |  | 3.4 |  |  | 26.9 |  |  | 19.7 |
Thermal | 9.0 |  |  | 8.5 |  |  | 36.5 |  |  | 30.6 |
Total Non-Regulated Energy Sales | $ | 85.7 |  |  | $ | 73.7 |  |  | $ | 268.0 |  |  | $ | 256.0 |
Less: |  |  |  |  |  |  |
Cost of Sales - Energy 2 | (3.6) |  |  | (1.4) |  |  | (12.5) |  |  | (5.1) |
Cost of Sales - Thermal | (7.0) |  |  | (3.5) |  |  | (24.0) |  |  | (11.5) |
Realized gain (loss) on hedges 3 | — |  |  | (0.2) |  |  | (0.1) |  |  | (1.1) |
Net Energy Sales 7, 8 | $ | 75.1 |  |  | $ | 68.6 |  |  | $ | 231.4 |  |  | $ | 238.3 |
Renewable Energy Credits 4 | 3.7 |  |  | 4.2 |  |  | 17.5 |  |  | 12.4 |
Other Revenue | 0.1 |  |  | 0.1 |  |  | 0.8 |  |  | 2.0 |
Total Net Revenue | $ | 78.9 |  |  | $ | 72.9 |  |  | $ | 249.7 |  |  | $ | 252.7 |
Expenses & Other Income |  |  |  |  |  |  |
Operating expenses | (24.8) |  |  | (19.3) |  |  | (104.3) |  |  | (74.0) |
Gain on sale of renewable assets | 29.1 |  |  | — |  |  | 29.1 |  |  | — |
Dividend, interest, equity and other income 5 | 13.5 |  |  | 25.1 |  |  | 84.0 |  |  | 94.0 |
Impacts from the Market Disruption Event on the Senate Wind Facility | — |  |  | — |  |  | 53.4 |  |  | — |
HLBV income 10 | 27.2 |  |  | 19.2 |  |  | 77.7 |  |  | 63.0 |
Divisional Operating Profit 6,7,9 | $ | 123.9 |  |  | $ | 97.9 |  |  | $ | 389.6 |  |  | $ | 335.7 |

Algonquin Power & Utilities Corp. - Management Discussion & Analysis | 31

1 | Many of the Renewable Energy Group’s PPAs include annual rate increases. However, a change to the weighted average production levels resulting from higher average production from facilities that earn lower energy rates can result in a lower weighted average energy rate earned by the division as compared to the same period in the prior year. Includes the impacts from the Market Disruption Event on the Senate Wind Facility.
2 | Cost of Sales - Energy consists of energy purchases in the Maritime Region to manage the energy sales from the Tinker Hydro Facility which is sold to retail and industrial customers under multi-year contracts.
3 | See Note 24(b)(iv) in the annual consolidated financial statements.
4 | Qualifying renewable energy projects receive RECs for the generation and delivery of renewable energy to the power grid. The RECs represent proof that 1 MW-hr of electricity was generated from an eligible energy source.
5 | Includes dividends received from Atlantica and related parties (see Note 8 and 16 in the annual consolidated financial statements) as well as the equity investment in the Texas Coastal Wind Facilities (Stella, Cranell, East Raymond and West Raymond).
6 | Certain prior year items have been reclassified to conform to current year presentation.
7 | See Caution Concerning Non-GAAP Measures.
8 | This tabl e contains a reconciliation of Net Energy Sales to revenue. The relevant sections of the table are derived from and should be read in conjunction with the consolidated statement of operations and Note 21 in the annual consolidated financial statements,“Segmented information”. This supplementary disclosure is intended to more fully explain disclosures related to Net Energy Sales and provides additional information related to the operating performance of AQN. Investors are cautioned that Net Energy Sales should not be construed as a n alternative to revenue.
9 | This table contains a reconciliation of Divisional Operating Profit to revenue. The relevant sections of the table are derived from and should be read in conj unction with the consolidated statement of operations and Note 21 in the annual consolidated financial statements, “Segmented Information”. This supplementary disclosure is intended to more fully explain disclosures related to Divisional Operating Profit and provides additional information related to the operating performance of the Renewable Energy Group. Investors are cautioned that Divisional Operating Profit should not be construed as an alternative to revenue.
10 | HLBV income represents the value of net tax attributes earned by the Renewable Energy Group in the period primarily from electricity generated by certain of its U.S. wind and U.S. solar generation facilities. Production tax credits ("PTCs") are earned as wind energy is generated based on a dollar per kW-hr rate prescribed in applicable federal and state statutes. For the three and twelve months ended December 31, 2021, the Renewable Energy Group's eligible facilities generated 1,418.4 and 4,419.2 GW-hrs representing approximately $35.5 million and $110.5 million in PTCs earned as compared to 765.4 and 2,600.4 GW-hrs representing $19.1 million and $65.0 million in PTCs earned during the same period in 2020. The majority of the PTCs have been allocated to tax equity investors to monetize the value to AQN of the PTCs and other tax attributes which are the primary drivers of HLBV income offset by the return earned by the investor. Some PTCs have been utilized directly by the Company to lower its overall effective tax rate

Algonquin Power & Utilities Corp. - Management Discussion & Analysis | 32

2021 Fourth Quarter Operating Results
For the three months ended December 31, 2021, the Renewable Energy Group’s facilities generated operating revenue of $85.7 million (i.e., non-regulated energy sales) as compared to $73.7 million in the comparable period in the prior year.
For the three months ended December 31, 2021, the Renewable Energy Group's facilities generated $123.9 million of Divisional Operating Profit as compared to $97.9 million during the same p eriod in 2020, which represents an increase of $26.0 million or 26.6%, excluding corporate administration expenses (see Caution Concerning Non-GAAP Measures).
Highlights of the changes are summarized in the following table:

(all dollar amounts in $ millions) | Three months ended December 31
Prior Period Divisional Operating Profit 1 | $ | 97.9 |
Existing Facilities and Investments |
Hydro: Decrease is primarily due to lower production and higher operating expenses in the Quebec Region. | (1.1) |
Wind Canada: Decrease is primarily due to lower production for the St. Damase, Morse and Amherst Wind Facilities. | (0.8) |
Wind U.S.: Decrease is primarily due to lower production for the Minonk, Shady Oaks, and Deerfield Wind Facilities and higher operating expenses, partially offset by higher overall HLBV income and higher REC revenue across the U.S. Wind Facilities. | (1.9) |
Solar: Decrease is primarily due to lower HLBV income for the Great Bay I Solar Facility. | (1.2) |
Thermal: Decrease is primarily due to higher carbon compliance costs and unfavourable capacity pricing for the Sanger Thermal Facility. | (2.6) |
Investments: Increase is primarily due to higher dividends from AQN's investment in Atlantica.2 | 4.4 |
Other: Decrease is primarily due to higher administrative fees received in 2020 from joint venture construction projects. | (1.8) |
| (5.0) |
New Facilities and Investments |
Wind U.S.: Sugar Creek Wind Facility (full COD in November 2020) and Maverick Creek Wind Facility (full COD April 2021). | 14.6 |
Solar: Great Bay II Solar Facility (full COD in August 2020) and Altavista Solar Facility (full COD in June 2021). | 0.5 |
Other: Increase is primarily due to a gain on the sale of the New Market Solar Project to a joint venture between the Company and its construction partner Ares (as defined below) partially offset by equity loss from the investment in the Texas Coastal Wind Facilities driven by lower production, unfavorable pricing and HLBV losses incurred by the investment. | 14.6 |
| 29.7 |
Foreign Exchange | 1.3 |
Current Period Divisional Operating Profit 1 | $ | 123.9 |

1 | See Caution Concerning Non-GAAP Measures.
2 | See Note 8 and 16 in the annual consolidated financial statements.

Algonquin Power & Utilities Corp. - Management Discussion & Analysis | 33

2021 Annual Operating Results
For the twelve months ended December 31, 2021, the Renewable Energy Group's facilities generated operating revenue of $268.0 million (i.e., non-regulated energy sales) as compared to $256.0 million in the prior year.,
For the twelve months ended December 31, 2021, the Renewable Energy Group's facilities generated $389.6 million of Divisional Operating Profit as compared to $335.7 million during the sam e period in 2020, which represents an increase of $53.9 million or 16.1%, excluding corporate administration expenses (see Caution Concerning Non-GAAP Measures).
Highlights of the changes are summarized in the following table:

(all dollar amounts in $ millions) | Twelve months ended December 31
Prior Period Divisional Operating Profit 1 | $ | 335.7 |
Existing Facilities |
Hydro: Decrease is primarily due to lower production and higher operating expenses in the Quebec Region. | (3.3) |
Wind Canada: Decrease is primarily due to lower overall production. | (2.2) |
Wind U.S.: Decrease is primarily due to lower overall production. | (2.6) |
Solar: Decrease is primarily due to lower HLBV income for the Great Bay I Solar Facility, partially offset by favourable capacity pricing. | (0.4) |
Thermal: Decrease is due to higher property taxes and higher operating costs at the Windsor Locks Thermal Facility as well as higher carbon compliance costs and lower capacity pricing for the Sanger Thermal Facility. | (7.8) |
Investments: Increase is primarily due to higher dividends from AQN's investment in Atlantica.2 | 11.9 |
Other: Decrease is primarily due to higher administrative fees received in 2020 from joint venture construction projects. | (3.4) |
| (7.8) |
New Facilities and Investments |
Wind U.S.: Sugar Creek Wind Facility (full COD in November 2020) and Maverick Creek Wind Facility (full COD in April 2021). | 41.1 |
Solar: Great Bay II Solar Facility (full COD in August 2020) and Altavista Solar Facility (full COD in June 2021). | 5.7 |
Other: Increase is primarily due to a gain on the sale of the New Market Solar Project to a joint venture between the Company and its construction partner Ares, partially offset by an equity loss from the investment in the Texas Coastal Wind Facilities primarily as a result of the Midwest Extreme Weather Event and HLBV losses recognized. | 9.0 |
| 55.8 |
Foreign Exchange | 5.9 |
Current Period Divisional Operating Profit 1 | $ | 389.6 |

1 | See Caution Concerning Non-GAAP Measures.
2 | See Note 8 and 16 in the annual consolidated financial statements.

Algonquin Power & Utilities Corp. - Management Discussion & Analysis | 34

AQN: CORPORATE AND OTHER EXPENSES

| Three months ended December 31 |  | Twelve months ended December 31
(all dollar amounts in $ millions) | 2021 |  | 2020 |  | 2021 |  | 2020
Corporate and other expenses: |  |  |  |  |  |  |
Administrative expenses | $ | 17.8 |  |  | $ | 12.6 |  |  | $ | 66.7 |  |  | $ | 63.1 |
Loss (gain) on foreign exchange | 1.0 |  |  | 3.5 |  |  | 4.4 |  |  | (2.1) |
Interest expense | 50.1 |  |  | 45.3 |  |  | 209.6 |  |  | 181.9 |
Depreciation and amortization | 110.8 |  |  | 88.0 |  |  | 403.0 |  |  | 314.1 |
Change in value of investments carried at fair value | (61.0) |  |  | (464.0) |  |  | 122.4 |  |  | (559.7) |
Interest, dividend, equity, and other loss (income)1 | 0.6 |  |  | (5.4) |  |  | 6.4 |  |  | (3.3) |
Pension and other post-employment non-service costs | 4.9 |  |  | 4.7 |  |  | 16.3 |  |  | 14.1 |
Other net losses | 11.9 |  |  | 16.6 |  |  | 22.9 |  |  | 61.3 |
Loss (gain) on derivative financial instruments | (0.3) |  |  | 0.8 |  |  | 1.7 |  |  | (1.0) |
Income tax expense (recovery) | 1.8 |  |  | 51.1 |  |  | (43.4) |  |  | 64.6 |

1 | Excludes income directly pertaining to the Regulated Services and Renewable Energy Groups (disclosed in the relevant sections).

2021 Fourth Quarter Corporate and Other Expenses
For the three months ended December 31, 2021, administrative expenses totaled $17.8 million as compared to $12.6 million in the same period in 2020 primarily related to timing of expenses incurred.
For the three months ended December 31, 2021, interest expense totaled $50.1 million as compared to $45.3 million in the same period in 2020 due to the funding of capital deployed in 2021 primarily related to renewable energy projects that have reached COD.
For the three months ended December 31, 2021, depreciation expense totaled $110.8 million as compared to $88.0 million in the same period in 2020. The increase was primarily due to higher overall property, plant and equipment, and the acquisitions of Ascendant and ESSAL.
For the three months ended December 31, 2021, change in investments carried at fair value totaled a gain of $61.0 million as compared to a gain of $464.0 million in 2020. The Company records certain of its investments, including Atlantica, using the fair value method and accordingly any change in the fair value of the investment is recorded in the Statement of Operations (see Note 8 in the annual c onsolidated financial statements).
For the three months ended December 31, 2021, pension and post-employment non-service costs totaled $4.9 million as compared to $4.7 million in 2020.
For the three months ended December 31, 2021, other net losses were $11.9 million as compared to $16.6 million in the same period in 2020. The net losses in 2021 were primarily due to acquisition and transition-related costs, and costs related to the Granite Bridge Project. The net losses in 2020 were primarily due to management succession and retirement expenses, costs relating to the condemnation proceedings for Liberty Utilities (Apple Valley Ranchos Water) Corp., and costs related to the Granite Bridge Project. See Note 19 in the annual consolidated financial statements for further details.
For the three months ended December 31, 2021, the loss on derivative financial instruments totaled $0.3 million as compared to a gain of $0.8 million in the same period in 2020. Both the losses and gains in 2021 and 2020 respectively were primarily related to mark-to-markets on energy derivatives.
For the three months ended December 31, 2021, an income tax expense of $1.8 million was recorded as compared to an income tax expense of $51.1 million during the same period in 2020. The decrease in income tax expense was primarily due to the tax impact associated with the change in fair value of the investment in Atlantica. For the three months ended December 31, 2021, the Company accrued $14.1 million of investment tax credits ("ITCs") and PTCs associated with renewable energy projects that were placed in service by the end of 2021.

Algonquin Power & Utilities Corp. - Management Discussion & Analysis | 35

2021 Annual Corporate and Other Expenses
During the twelve months ended December 31, 2021, administrative expenses totaled $66.7 million as compared to $63.1 million in the same period in 2020.
For the twelve months ended December 31, 2021, interest expense totaled $209.6 million as compared to $181.9 million in the same period in 2020. The increase was primarily due to the acquisitions of Ascendant and ESSAL as well as the funding of capital deployed in 2021 primarily related to renewable energy projects that have reached COD.
For the twelve months ended December 31, 2021, depreciation expense totaled $403.0 million as compared to $314.1 million in the same period in 2020. The increase was primarily due to higher overall property, plant and equipment, and the acquisitions of Ascendant and ESSAL.
For the twelve months ended December 31, 2021, change in investments carried at fair value totaled a loss of $122.4 million as compared to a gain of $559.7 million in the same period in 2020. The Company records certain of its investments, including Atlantica, using the fair value method and accordingly any change in the fair value of the investment is recorded in the Statement of Operations (see Note 8 in the annual consolidated financial statements).
For the twelve months ended December 31, 2021, pension and post-employment non-service costs totaled $16.3 million as compared to $14.1 million in the same period in 2020. The increase in 2021 was primarily due to higher amortization of regulatory accounts and net actuarial losses, partially offset by a higher return on pension plan assets.
For the twelve months ended December 31, 2021, other net losses were $22.9 million as compared to $61.3 million in the same period in 2020. The net losses in 2021 were primarily due to a regulatory asset write down and acquisition and transition-related costs. The net losses in 2020 were primarily due to management succession and retirement expenses,
adjustments related to U.S. Tax Reform, costs related to the condemnation proceedings for Liberty Utilities (Apple Valley Ranchos Water) Corp., and costs related to the Granite Bridge Project. See Note 19 in the annual consolidated financial statements for further details.
For the twelve months ended December 31, 2021, the loss on derivative financial instruments totaled $1.7 million as compared to a gain of $1.0 million in the same period in 2020. Both the losses and gains in 2021 and 2020 respectively were primarily related to mark-to-markets on energy derivatives.
An income tax recovery of $43.4 million was recorded in the twelve months ended December 31, 2021, as compared to an income tax expense of $64.6 million during the same period in 2020. The decrease in income tax expense was primarily due to the tax impact associated with the change in fair value of the investment in Atlantica, the tax benefits associated with the impact of the Midwest Extreme Weather Event earlier in 2021, tax credits accrued, and a one-time income tax expense related to U.S. Tax Reform recorded in 2020, partially offset by higher operating income in 2021. For the twelve months ended December 31, 2021, the Company accrued $49.4 million of ITCs and PTCs associated with renewable energy projects that were placed in service by the end of 2021. On April 8, 2020, the IRS issued final regulations with respect to rules regarding certain hybrid arrangements as a result of U.S. Tax Reform. As a result of the final regulations, the Company recorded a one-time income tax expense of $9.3 million in the twelve months ended December 31, 2020, to reverse the benefit of deductions taken in a prior year.

Algonquin Power & Utilities Corp. - Management Discussion & Analysis | 36

NON-GAAP FINANCIAL MEASURES
Reconciliation of Adjusted EBITDA to Net Earnings
The following table is derived from and should be read in conjunction with the consolidated statement of operations. This supplementary disclosure is intended to more fully explain disclosures related to Adjusted EBITDA and provides additional information related to the operating performance of AQN. Investors are cautioned that this measure should not be construed as an alternative to U.S. GAAP consolidated net earnings.

| Three months ended December 31 1 |  | Twelve months ended December 31
(all dollar amounts in $ millions) | 2021 |  | 2020 |  | 2021 |  | 2020
Net earnings attributable to shareholders | $ | 175.6 |  |  | $ | 504.2 |  |  | $ | 264.9 |  |  | $ | 782.5 |
Add (deduct): |  |  |  |  |  |  |
Net earnings attributable to the non-controlling interest, exclusive of HLBV 2 | 2.3 |  |  | 3.1 |  |  | 16.1 |  |  | 14.9 |
Income tax expense (recovery) | 1.8 |  |  | 51.1 |  |  | (43.4) |  |  | 64.6 |
Interest expense | 50.1 |  |  | 45.3 |  |  | 209.6 |  |  | 181.9 |
Other net losses 4 | 11.9 |  |  | 16.6 |  |  | 22.9 |  |  | 61.3 |
Pension and post-employment non-service costs | 4.9 |  |  | 4.7 |  |  | 16.3 |  |  | 14.1 |
Change in value of investments carried at fair value 3 | (61.0) |  |  | (464.0) |  |  | 122.4 |  |  | (559.7) |
Impacts from the Market Disruption Event on the Senate Wind Facility | — |  |  | — |  |  | 53.4 |  |  | — |
Costs related to tax equity financing | 0.5 |  |  | — |  |  | 5.7 |  |  | — |
Loss (gain) on derivative financial instruments | (0.3) |  |  | 0.8 |  |  | 1.7 |  |  | (1.0) |
Realized loss on energy derivative contracts | — |  |  | (0.2) |  |  | (0.1) |  |  | (1.1) |
Loss (gain) on foreign exchange | 1.0 |  |  | 3.5 |  |  | 4.4 |  |  | (2.1) |
Depreciation and amortization | 110.8 |  |  | 88.0 |  |  | 403.0 |  |  | 314.1 |
Adjusted EBITDA | $ | 297.6 |  |  | $ | 253.1 |  |  | $ | 1,076.9 |  |  | $ | 869.5 |

1 | Amounts for the three months ended December 31, 2021 and 2020 are derived by subtracting the Company's results for the nine months ended September 30, 2021 and 2020 from the Company's 2021 and 2020 annual results, respectively.
2 | HLBV represents the value of net tax attributes earned during the period primarily from electricity generated by certain U.S. wind power and U.S. solar generation facilities. HLBV earned in the three and twelve months ended December 31, 2021 amounted to $34.4 million and $95.3 million, respectively, as compared to $20.6 million and $69.7 million during the same period in 2020.
3 | See Note 8 in the annual consolidated financial statements.
4 | See Note 19 in the annual consolidated financial statements.

Algonquin Power & Utilities Corp. - Management Discussion & Analysis | 37

Reconciliation of Adjusted Net Earnings to Net Earnings
The following table is derived from and should be read in conjunction with the consolidated statement of operations. This supplementary disclosure is intended to more fully explain disclosures related to Adjusted Net Earnings and provides additional information related to the operating performance of AQN. Investors are cautioned that this measure should not be construed as an alternative to consolidated net earnings in accordance with U.S. GAAP.
The following table shows the reconciliation of net earnings to Adjusted Net Earnings exclusive of these items:

| Three months ended December 31 1 |  | Twelve months ended December 31
(all dollar amounts in $ millions except per share information) | 2021 |  | 2020 |  | 2021 |  | 2020
Net earnings attributable to shareholders | $ | 175.6 |  |  | $ | 504.2 |  |  | $ | 264.9 |  |  | $ | 782.5 |
Add (deduct): |  |  |  |  |  |  |
Loss (gain) on derivative financial instruments | (0.3) |  |  | 0.8 |  |  | 1.7 |  |  | (1.0) |
Realized loss on energy derivative contracts | — |  |  | (0.2) |  |  | (0.1) |  |  | (1.1) |
Other net losses 3 | 11.9 |  |  | 16.6 |  |  | 22.9 |  |  | 61.3 |
Loss (gain) on foreign exchange | 1.0 |  |  | 3.5 |  |  | 4.4 |  |  | (2.1) |
Change in value of investments carried at fair value 2 | (61.0) |  |  | (464.0) |  |  | 122.4 |  |  | (559.7) |
Impacts from the Market Disruption Event on the Senate Wind Facility | — |  |  | — |  |  | 53.4 |  |  | — |
Costs related to tax equity financing and other adjustments | 0.5 |  |  | — |  |  | 5.7 |  |  | 1.0 |
Adjustment for taxes related to above | 8.6 |  |  | 66.1 |  |  | (25.7) |  |  | 84.9 |
Adjusted Net Earnings | $ | 136.3 |  |  | $ | 127.0 |  |  | $ | 449.6 |  |  | $ | 365.8 |
Adjusted Net Earnings per common share | $ | 0.21 |  |  | $ | 0.21 |  |  | $ | 0.71 |  |  | $ | 0.64 |

1 | Amounts for the three months ended December 31, 2021 and 2020 are derived by subtracting the Company's results for the nine months ended September 30, 2021 and 2020 from the Company's 2021 and 2020 annual results, respectively.
2 | See Note 8 in the annual consolidated financial statements.
3 | See Note 19 in the annual consolidated financial statements.

For the three months ended December 31, 2021, Adjusted Net Earnings totaled $136.3 million as compared to Adjusted Net Earnings of $127.0 million for the same period in 2020, an increase of $9.3 million.
For the twelve months ended December 31, 2021, Adjusted Net earnings totaled $449.6 million as compared to Adjusted Net Earnings of $365.8 million for the same period in 2020, an increase of $83.8 million.

Algonquin Power & Utilities Corp. - Management Discussion & Analysis | 38

Reconciliation of Adjusted Funds from Operations to Cash Flows from Operating Activities
The following table is derived from and should be read in conjunction with the consolidated statement of operations and consolidated statement of cash flows. This supplementary disclosure is intended to more fully explain disclosures related to Adjusted Funds from Operations and provides additional information related to the operating performance of AQN. Investors are cautioned that this measure should not be construed as an alternative to cash flows from operating activities in accordance with U.S GAAP.
The following table shows the reconciliation of cash flows from operating activities to Adjusted Funds from Operations exclusive of these items:

| Three months ended December 31 1 |  | Twelve months ended December 31
(all dollar amounts in $ millions) | 2021 |  | 2020 |  | 2021 |  | 2020
Cash flows from operating activities | $ | 126.5 |  |  | $ | 174.0 |  |  | $ | 157.5 |  |  | $ | 505.2 |
Add (deduct): |  |  |  |  |  |  |
Changes in non-cash operating items | 84.4 |  |  | (2.8) |  |  | 522.0 |  |  | 77.5 |
Production based cash contributions from non-controlling interests | — |  |  | — |  |  | 4.8 |  |  | 3.4 |
Impacts from the Market Disruption Event on the Senate Wind Facility | — |  |  | — |  |  | 53.4 |  |  | — |
Costs related to tax equity financing | 0.5 |  |  | — |  |  | 5.7 |  |  | — |
Acquisition-related costs | 9.8 |  |  | 8.1 |  |  | 14.5 |  |  | 14.1 |
Adjusted Funds from Operations | $ | 221.2 |  |  | $ | 179.3 |  |  | $ | 757.9 |  |  | $ | 600.2 |

1 | Amounts for the three months ended December 31, 2021 and 2020 are derived by subtracting the Company's results for the nine months ended September 30, 2021 and 2020 from the Company's 2021 and 2020 annual results, respectively.

For the three months ended December 31, 2021, Adjusted Funds from Operations totaled $221.2 million as compared to Adjusted Funds from Operations of $179.3 million for the same period in 2020, an increase of $41.9 million.
For the twelve months ended December 31, 2021, Adjusted Funds from Operations totaled $757.9 million as compared to Adjusted Funds from Operations of $600.2 million for the same period in 2020, an increase of $157.7 million.
CORPORATE DEVELOPMENT ACTIVITIES
The Company undertakes development activities working with a global reach to identify, develop, and construct both regulated and non-regulated renewable power generating facilities, power transmission lines, water infrastructure assets, and other complementary infrastructure projects as well as to invest in local utility electric, natural gas and water distribution systems.
The Company has announced a capital investment plan of approximately $12.4 billion consisting of approximately $8.8 billion of anticipated investments by its Regulated Services Group and approximately $3.6 billion of anticipated investments by its Renewable Energy Group for the period from 2022 through the end of 2026.
On January 27, 2021, Empire closed its acquisition of the North Fork Ridge Wind Facility, and on May 5, 2021 Empire closed the acquisition of the Neosho Ridge and Kings Point Wind Facilities. Construction of the Kings Point and Neosho Ridge Wind Facilities is complete with the exception of civil remediation. Neosho Ridge continues to operate under an interim interconnection agreement. North Fork Ridge and Kings Point have executed General Interconnection Agreements, and Neosho Ridge is expected to execute a General Interconnection Agreement in March 2022. Empire filed rate reviews in Missouri and Kansas in May 2021 seeking cost recovery of the Empire Wind Facilities (see Regulatory Proceedings).

Algonquin Power & Utilities Corp. - Management Discussion & Analysis | 39

SUMMARY OF PROPERTY, PLANT, AND EQUIPMENT EXPENDITURES

| Three months ended December 31 |  | Twelve months ended December 31
(all dollar amounts in $ millions) | 2021 |  | 2020 |  | 2021 |  | 2020
Regulated Services Group |  |  |  |  |  |  |
Rate Base Maintenance | 74.8 |  |  | 54.7 |  |  | 280.6 |  |  | 210.8 |
Rate Base Growth | 171.3 |  |  | 242.0 |  |  | 1,668.9 |  |  | 537.4 |
Property, Plant & Equipment Acquired 1 | — |  |  | 656.5 |  |  | — |  |  | 656.5 |
| $ | 246.1 |  |  | $ | 953.2 |  |  | $ | 1,949.5 |  |  | $ | 1,404.7 |
Renewable Energy Group |  |  |  |  |  |  |
Maintenance | $ | 10.4 |  |  | $ | 11.4 |  |  | $ | 45.9 |  |  | $ | 27.5 |
Investment in Capital Projects 1 | 45.2 |  |  | (126.4) |  |  | 1,555.5 |  |  | 103.3 |
International Investments | (20.3) |  |  | (11.9) |  |  | 120.8 |  |  | 10.3 |
| $ | 35.3 |  |  | $ | (126.9) |  |  | $ | 1,722.2 |  |  | $ | 141.1 |
Total Capital Expenditures | $ | 281.4 |  |  | $ | 826.3 |  |  | $ | 3,671.7 |  |  | $ | 1,545.8 |

1 | Includes expenditures on Property Plant & Equipment, equity-method investees, and acquisitions of operating entities that may have been jointly developed by the Company with another third party developer. Excludes temporary advances to joint venture partners in connection with capital projects under development or construction.

2021 Fourth Quarter Property Plant and Equipment Expenditures
During the three months ended December 31, 2021, the Regulated Services Group invested $246.1 million in capital expenditures as compared to $953.2 million during the same period in 2020. The Regulated Services Group's investment was primarily related to the construction of transmission and distribution main replacements, work on new and existing substation assets, and initiatives relating to the safety and reliability of the electric and gas systems.
During the three months ended December 31, 2021, the Renewable Energy Group incurred capital expenditures of $35.3 million as compared to $126.9 million net capital reimbursements during the same period in 2020. The Renewable Energy Group's investment was primarily related to the development and/or construction of ongoing maintenance capital at existing operating sites.
2021 Annual Property Plant and Equipment Expenditures
During the twelve months ended December 31, 2021, the Regulated Services Group invested $1,949.5 million in capital expenditures as compared to $1,404.7 million during the same period in 2020. The Regulated Services Group's investment was primarily related to the acquisition of the Empire Wind Facilities ($1,095.3 million), construction of transmission and distribution main replacements, the completion and start of work on new and existing substation assets, and initiatives relating to the safety and reliability of the electric and gas systems.
During the twelve months ended December 31, 2021, the Renewable Energy Group incurred capital expenditures of $1,722.2 million as compared to $141.1 million during the same period in 2020. The Renewable Energy Group's investment was primarily related to the acquisitions of the previously unowned portions of the Maverick Creek and Sugar Creek Wind Projects and Altavista Solar Project from its joint venture partners, the acquisition of a 51% interest in the Texas Coastal Wind Facilities, to advance the development and/or construction of the Dimension and Carvers Creek projects and ongoing sustaining capital at existing operating sites. The Company also made an investment of approximately $132.7 million of addi tional ordinary shares of Atlantica purchased through a subscription agreement that was completed in early 2021 (see Note 8 (a) in the annual consolidated financial statements).

Algonquin Power & Utilities Corp. - Management Discussion & Analysis | 40

2022 Capital Investments
The following discussion should be read in conjunction with the Forward-Looking Statements and Forward-Looking Information section of this MD&A.
Over the course of the 2022 financial year, the Company expects to spend between approximately $4.34 billion and $4.68 billion on capital investment opportunities. Actual expenditures in 2022 may vary due to, among other things, the impacts of COVID-19 and related response measures, the timing of various project investments and acquisitions, the availability of financing on acceptable terms, and realized foreign exchange rates.
Ranges of expected capital investment in the 2022 financial year are as follows:

(all dollar amounts in $ millions) |  |  |
Regulated Services Group: |  |  |
Rate Base Maintenance | $ | 390.0 |  | - | $ | 440.0 |
Rate Base Growth | 400.0 |  | - | 440.0 |
Rate Base Acquisitions | 3,510.0 |  | - | 3,720.0 |
Total Regulated Services Group: | $ | 4,300.0 |  | - | $ | 4,600.0 |
Renewable Energy Group: |  |  |
Maintenance | $ | 35.0 |  | - | $ | 50.0 |
Investment in Capital Projects | 5.0 |  | - | 30.0 |
Total Renewable Energy Group: | $ | 40.0 |  | - | $ | 80.0 |
Total 2022 Capital Investments | $ | 4,340.0 |  | - | $ | 4,680.0 |

The Regulated Services Group expects to spend between $4,300.0 million and $4,600.0 million over the course of 2022 primarily attributable to rate base acquisitions between $3,510.0 million and $3,720.0 million. In January 2022, the Regulated Services Group closed the acquisition of Liberty NY Water for a purchase price of approximately $608.0 million excluding transaction costs. Furthermore, in October 2021, an agreement was reached to acquire Kentucky Power and Kentucky TransCo for a total purchase price of approximately $2,846.0 million excluding transaction costs. The Kentucky Power Transaction is expected to close in mid-2022. The remaining Regulated Services Group spend is expected to contribute to continued efforts to expand operations, improve the reliability of the utility systems and broaden the technologies used to better serve its service areas. Project spending includes capital for structural improvements, specifically in relation to refurbishing substations, replacing poles and wires, drilling and equipping aquifers, main replacements, and reservoir pumping stations.
The Renewable Energy Group expects to spend between $40.0 million and $80.0 million over the course of 2022 to develop or further invest in development and construction (as applicable) of the Renewable Energy Group's wind and solar projects. Furthermore, the Renewable Energy Group plans to spend between $35.0 million and $50.0 million on various operational solar, thermal, and wind assets to maintain safety, regulatory, and operational efficiencies.
The Company expects to fund its 2022 capital plan through a combination of retained cash, tax equity funding, senior notes, subordinated notes, bank revolving and term credit facilities, and common equity or equity linked instruments.

Algonquin Power & Utilities Corp. - Management Discussion & Analysis | 41

LIQUIDITY AND CAPITAL RESERVES
AQN has revolving credit and letter of credit facilities as well as separate credit facilities for the Regulated Services Group and the Renewable Energy Group to manage the liquidity and working capital requirements of each division (collectively the “Bank Credit Facilities”).
Bank Credit Facilities
The following table sets out the Bank Credit Facilities available to AQN and its operating groups as at December 31, 2021:

| As at December 31, 2021 |  | As at Dec 31, 2020
(all dollar amounts in $ millions) | Corporate |  | Regulated Services Group |  | Renewable Energy Group |  | Total |  | Total
Revolving and term credit facilities | $ | 550.0 |  | 1 | $ | 1,675.0 |  |  | $ | 850.0 |  | 2 | $ | 3,075.0 |  |  | $ | 3,575.0 |
Funds drawn on facilities/ commercial paper issued | (289.9) |  |  | (403.0) |  |  | (14.7) |  |  | (707.6) |  |  | (345.5) |
Letters of credit issued | (23.0) |  |  | (73.0) |  |  | (221.2) |  |  | (317.2) |  |  | (441.4) |
Liquidity available under the facilities | 237.1 |  |  | 1,199.0 |  |  | 614.1 |  |  | 2,050.2 |  |  | 2,788.1 |
Undrawn portion of uncommitted letter of credit facilities | (30.8) |  |  | — |  |  | (193.2) |  |  | (224.0) |  |  | (105.8) |
Cash on hand |  |  |  |  |  |  | 125.2 |  |  | 101.6 |
Total Liquidity and Capital Reserves | $ | 206.3 |  |  | $ | 1,199.0 |  |  | $ | 420.9 |  |  | $ | 1,951.4 |  |  | $ | 2,783.9 |
1 Includes a $50 million uncommitted standalone letter of credit facility.
2 Includes a $350 million uncommitted standalone letter of credit facility.

Corporate
As at December 31, 2021, the Company's $500.0 million senior unsecured syndicated revolving credit facility (the "Corporate Credit Facility") had $289.9 million drawn and had $3.8 million of outstanding letters of credit. The Corporate Credit Facility matures on July 12, 2024.
As at December 31, 2021, the Company had also issued $19.2 million of letters of credit from its $50 million uncommitted bi-lateral letter of credit facility.
In conjunction with the Kentucky Power Transaction, AQN obtained a $2,725.0 million syndicated acquisition financing commitment. The acquisition financing commitment is subject to customary terms and conditions, including certain commitment reductions upon closing of permanent financing. $1,086.0 million remains available under the acquisition financing commitment as at March 3, 2022.
Regulated Services Group
As at December 31, 2021, the Regulated Services Group's $500.0 million senior unsecured syndicated revolving credit facility (the "Regulated Services Credit Facility") had no amounts drawn and had $73.0 million of outstanding letters of credit. The Regulated Services Credit Facility matures on February 23, 2023. As at December 31, 2021, $338.7 million of commercial paper was issued and outstanding.
Through the acquisition of Ascendant in the fourth quarter of 2020, the Regulated Services Group acquired a $75.0 million senior unsecured revolving credit facility (the "BELCO Credit Facility"). As at December 31, 2021, the BELCO Credit Facility had $64.3 million drawn. The BELCO Credit Facility was amended to extend the maturity to June 30, 2022. The Company expects to refinance the credit facility before maturity.
On December 20, 2021, the Regulated Services Group entered into a $1.1 billion senior unsecured syndicated delayed draw term facility ("the "Regulated Services Delayed Draw Term Facility") which matures on December 19, 2022. As at December 31, 2021, the Regulated Services Delayed Draw Term Facility had no amounts drawn. Subsequent to quarter-end on January 3, 2022, the purchase price, plus certain acquisition costs, for the acquisition of Liberty NY Water of approximately $610.4 million was funded through a draw on the Regulated Services Delayed Draw Term Facility.
Renewable Energy Group
As at December 31, 2021, the Renewable Energy Group's bank lines consisted of a $500.0 million senior unsecured syndicated revolving credit facility (the "Renewable Energy Credit Facility") maturing on October 6, 2023 and a $350.0

Algonquin Power & Utilities Corp. - Management Discussion & Analysis | 42

million letter of credit facility ("Renewable Energy LC Facility") that was amended to extend the maturity to June 30, 2023. As at December 31, 2021, the Renewable Energy Credit Facility had $14.7 million drawn and had $64.4 million in outstanding letters of credit. As at December 31, 2021, the Renewable Energy LC Facility had $156.8 million in outstanding letters of credit.
Long Term Debt
On February 15, 2021, the Company repaid a C$150.0 million senior unsecured note on its maturity.
Subsequent to year-end on February 15, 2022, the Company repaid a C$200.0 million senior unsecured note on its maturity.
Issuance of C$400 Million of Green Senior Unsecured Debentures
On April 9, 2021, Algonquin Power Co. ("APCo"), the parent company for the U.S. and Canadian generating assets under the Renewable Energy Group, issued C$400.0 million of Debentures. The Debentures were offered at a price of C$999.92 per C$1,000 principal amount. The Debentures were assigned a BBB rating from Standard & Poor's Financial Services LLC, ("S&P"), Fitch Ratings Inc. ("Fitch") and DBRS Limited ("DBRS"). Concurrent with the offering of the Debentures, the Renewable Energy Group entered into a cross currency swap, coterminous with the Debentures, to convert the Canadian dollar denominated proceeds into U.S. dollars, resulting in an effective interest rate throughout the term of the Debentures of approximately 2.82%. The net proceeds from the offering of the Debentures were or will be, as applicable, used to finance or refinance investments in renewable power generation and clean energy technologies.
Issuance of $1.15 Billion of Green Equity Units
On June 23, 2021, the Company closed an underwritten marketed public offering of 20,000,000 Green Equity Units for total gross proceeds of $1.0 billion. The underwriters subsequently exercised their option to purchase an additional 3,000,000 Green Equity Units on the same terms, bringing total gross proceeds including the over-allotment to $1.15 billion.
Each Green Equity Unit was issued in a stated amount of $50 and, at issuance, consisted of a contract to purchase common shares of the Company and a 1/20, or 5%, undivided beneficial ownership interest in a $1,000 principal amount remarketable senior note of the Company due June 15, 2026. Pursuant to the purchase contracts, holders are required to purchase common shares of the Company on June 15, 2024.
Total annual distributions on the Green Equity Units are at the rate of 7.75%, consisting of quarterly interest payments on the remarketable senior notes at a rate of 1.18% per year and, subject to any permitted deferral, quarterly contract adjustment payments on the purchase contracts at a rate of 6.57% per year. The reference price for the Green Equity Units is $15.00 per AQN common share. The minimum settlement rate under the purchase contracts is 2.7778 common shares, which is approximately equal to the $50 stated amount per Green Equity Unit, divided by the threshold appreciation price of $18.00 per common share, which represents a premium of 20% over the reference price. The maximum settlement rate under the purchase contracts is 3.3333 common shares, which is approximately equal to the $50 stated amount per Green Equity Unit, divided by the reference price. Each of the settlement rates is subject to adjustment in certain circumstances.
The Green Equity Units are expected to receive 100% equity credit from S&P as of the issuance date and 100% equity credit from Fitch and DBRS upon conversion.
The dilutive effect of the Green Equity Units on net earnings per share is calculated using the treasury stock method of accounting (see Note 12(a) in the annual consolidated financial statements).
The net proceeds of the offering were approximately $1.12 billion in the aggregate (including the over-allotment), after deducting underwriting discounts and commissions but before deducting estimated expenses of the offering. The net proceeds of the offering have been or will be, as applicable, used to finance or refinance investments in renewable energy generation projects or facilities or other clean energy technologies in accordance with the Company's Green Financing Framework.
The Green Equity Units (that are in the form of "corporate units") are listed on the New York Stock Exchange ("NYSE") under the ticker symbol "AQNU".
Issuance of approximately $1.1 Billion of Subordinated Notes
Subsequent to year-end on January 18, 2022, the Company closed (i) an underwritten public offering in the United States of $750 million aggregate principal amount of the U.S. Notes; and (ii) an underwritten public offering in Canada of C$400 million aggregate principal amount of the Canadian Notes. Concurrent with the pricing of the Note Offerings, the Company entered into a cross currency interest rate swap to convert the Ca nadian dollar denominated proceeds from the Canadian Note Offering into U.S. dollars and a forward starting swap to fix the interest rate for the second five year term of the U.S. Notes, resulting in an anticipated effective interest rate to the Company of approximately 4.95% throughout the first ten year period of the Notes. The Note Offerings were assigned a BB+ rating from S&P and Fitch.

Algonquin Power & Utilities Corp. - Management Discussion & Analysis | 43

The Company intends to use the net proceeds of the Note Offerings to partially finance the Kentucky Power Transaction, provided that, in the short-term, prior to the closing of the Kentucky Power Transaction, the Company has used a portion of, and expects to use the remainder of such net proceeds to repay certain indebtedness of the Corporation and its subsidiaries
Credit Ratings
AQN has a long term consolidated corporate credit rating of BBB from S&P, a BBB rating from DBRS and a BBB issuer rating from Fitch. Liberty Utilities has a corporate credit rating of BBB from S&P and a BBB issuer rating from Fitch. Debt issued by Liberty Utilities Finance GP1 (“Liberty GP”) has a rating of BBB (high) from DBRS, BBB+ from Fitch and BBB from S&P. Empire has an issuer rating of BBB from S&P and a Baa1 rating from Moody's Investors Service, Inc. Liberty Utilities (Canada) LP, the parent company for the Canadian regulated utilities under the Regulated Services Group, has an issuer rating of BBB from DBRS. APCo has a BBB issuer rating from S&P, a BBB issuer rating from DBRS and a BBB issuer rating from Fitch.
On October 28, 2021, following the announcement of the Kentucky Power Transaction, each of DBRS, Fitch and S&P made announcements regarding the credit ratings of the Corporation and its subsidiaries.
Fitch affirmed (i) the existing issuer ratings of both the Corporation and Liberty Utilities (‘BBB’ Long-Term Issuer Default Rating (“IDR”) and ‘F2’ Short-Term IDR, respectively), and (ii) all the security ratings of the Corporation, Liberty Utilities and Liberty GP. Fitch also noted that the rating outlooks for the Corporation and Liberty Utilities are stable and that the credit ratings of APCo are unaffected by the Kentucky Power Transaction. Fitch noted that it views the Kentucky Power Transaction to be neutral to the credit quality of the Corporation and Liberty Utilities, given the underlying credit quality of Kentucky Power, and what Fitch expects to be a relatively credit-supportive financing plan for the Kentucky Power Transaction.
DBRS placed the Corporation’s ‘BBB’ Issuer Rating and ‘Pfd-3’ Preferred Shares ratings ‘Under Review with Developing Implications’. DBRS indicated that it views the Kentucky Power Transaction as a positive development from a business risk perspective due to the expected increase in the Corporation’s regulated assets and rate base and expected improvements in jurisdictional diversification and capital expenditure planning. Notwithstanding these potentially positive impacts, the ‘Under Review with Developing Implications’ rating action reflects DBRS’s view that the Corporation’s financing plan for the Kentucky Power Transaction, which may include the issuance of hybrid debt, could increase the Corporation’s nonconsolidated leverage. DBRS noted that if the Corporation’s nonconsolidated debt-to-capital ratio, as calculated by DBRS, rises significantly above 20% following the issuance of any hybrid debt, a negative rating action could be taken.
S&P revised its outlook on the Corporation, Liberty Utilities, APCo, Liberty GP and Empire from stable to negative, noting a lack of certainty regarding the Corporation’s financing plan for the Kentucky Power Transaction, beyond the Common Equity Offering, which could expose the Corporation to execution risks related to the procurement of credit supportive funding. S&P also noted that the negative outlook incorporates the possibility of any material adverse regulatory requirements which may be necessary to close the Kentucky Power Transaction. S&P also affirmed its ‘BBB’ issuer credit rating for each of the Corporation, Liberty Utilities, APCo, Liberty GP and Empire. Finally, S&P placed its rating on Liberty GP’s senior unsecured debt on CreditWatch with negative implications to reflect its view of the potential for such debt to be structurally subordinated following the closing of the Kentucky Power Transaction.

Algonquin Power & Utilities Corp. - Management Discussion & Analysis |

Contractual Obligations
Information concerning contractual obligations as of December 31, 2021 is shown below:

(all dollar amounts in $ millions) | Total |  | Due in less than 1 year |  | Due in 1 to 3 years |  | Due in 4 to 5 years |  | Due after 5 years
Principal repayments on debt obligations 1,2 | $ | 6,223.3 |  |  | $ | 834.6 |  |  | $ | 787.6 |  |  | $ | 1,217.2 |  |  | $ | 3,383.9 |
Advances in aid of construction | 82.6 |  |  | 1.7 |  |  | — |  |  | — |  |  | 80.9 |
Interest on long-term debt obligations 2 | 1,847.2 |  |  | 196.8 |  |  | 348.5 |  |  | 297.5 |  |  | 1,004.4 |
Purchase obligations | 614.0 |  |  | 614.0 |  |  | — |  |  | — |  |  | — |
Environmental obligations | 57.2 |  |  | 12.7 |  |  | 23.9 |  |  | 1.1 |  |  | 19.5 |
Derivative financial instruments: |  |  |  |  |  |  |  |  |
Cross currency interest rate swaps | 55.5 |  |  | 27.9 |  |  | 23.1 |  |  | 2.6 |  |  | 1.9 |
Interest rate swaps | 7.0 |  |  | 2.2 |  |  | 2.1 |  |  | 1.3 |  |  | 1.4 |
Energy derivative and commodity contracts | 63.0 |  |  | 8.5 |  |  | 20.2 |  |  | 16.5 |  |  | 17.8 |
Purchased power | 331.1 |  |  | 62.8 |  |  | 67.1 |  |  | 46.1 |  |  | 155.1 |
Gas delivery, service and supply agreements | 473.9 |  |  | 101.4 |  |  | 124.8 |  |  | 71.2 |  |  | 176.5 |
Service agreements | 635.9 |  |  | 65.2 |  |  | 118.0 |  |  | 105.1 |  |  | 347.6 |
Capital projects | 85.1 |  |  | 85.1 |  |  | — |  |  | — |  |  | — |
Land easements | 537.9 |  |  | 12.9 |  |  | 26.3 |  |  | 27.0 |  |  | 471.7 |
Contract adjustment payments on equity units | 187.6 |  |  | 75.6 |  |  | 112.0 |  |  | — |  |  | — |
Other obligations | 335.9 |  |  | 66.9 |  |  | 4.5 |  |  | 4.4 |  |  | 260.1 |
Total Obligations | $ | 11,537.2 |  |  | $ | 2,168.3 |  |  | $ | 1,658.1 |  |  | $ | 1,790.0 |  |  | $ | 5,920.8 |

1 | Exclusive of deferred financing costs, bond premium/discount, fair value adjustments at the time of issuance or acquisition.
2 | The Company's subordinated unsecured notes have a maturity in 2078 and 2079, respectively. However, the Company currently anticipates repaying in 2023 and 2029 upon exercising its redemption right.

Equity
The common shares of AQN are publicly traded on the Toronto Stock Exchange ("TSX") and the New York Stock Exchange ("NYSE") under the trading symbol "AQN". As at March 2, 2022, AQN had 673,685,148 issued and outstanding common shares.
AQN may issue an unlimited number of common shares. The holders of common shares are entitled to dividends, if and when declared; to one vote for each share at meetings of the holders of common shares; and to receive a pro rata share of any remaining property and assets of AQN upon liquidation, dissolution or winding up of AQN. All shares are of the same class and with equal rights and privileges and are not subject to future calls or assessments.
AQN is also authorized to issue an unlimited number of preferred shares, issuable in one or more series, containing terms and conditions as approved by the Board. As at December 31, 2021, AQN had outstanding:
•4,800,000 cumulative rate reset Series A preferred shares, yielding 5.162% annually for the five-year period ending on December 31, 2023;
•100 Series C preferred shares that were issued in exchange for 100 Class B limited partnership units by St. Leon Wind Energy LP; and
•4,000,000 cumulative rate reset Series D preferred shares, yielding 5.091% annually for the five year period ending on March 31, 2024.
In addition, AQN’s outstanding Green Equity Units (that are in the form of "corporate units") are listed on the NYSE under the ticker symbol "AQNU". As at March 3, 2021, there were 23,000,000 Green Equity Units outstanding. Pursuant to the purchase contract forming part of each outstanding Green Equity Unit, holders are required to purchase AQN common shares on June 15, 2024. The minimum settlement rate under each purchase contract is 2.7778 common shares and the maximum settlement rate is 3.3333 common shares, resulting in a minimum of 63,889,400 common shares and a maximum of 76,665,900 common shares issuable on settlement of the purchase contracts.

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C$800 million Bought Deal Common Equity Offering
On November 8, 2021, AQN closed the approximately C$800 million Common Equity Offering. The Company intends to use the net proceeds of the Common Equity Offering to partially finance the Kentucky Power Transaction provided that, in the short-term, prior to closing of the Kentucky Power Transaction, the Company has used such net proceeds to reduce amounts outstanding under existing credit facilities.
At-The-Market Equity Program
On May 15, 2020, AQN re-established an at-the-market equity program ("ATM program") that allowed the Company to issue up to $500 million of common shares from treasury to the public from time to time, at the Company's discretion, at the prevailing market price when issued on the TSX, the NYSE, or any other existing trading market for the common shares of the Company in Canada or the United States. On November 19, 2021, in connection with the filing of a new base shelf prospectus, AQN withdrew the base shelf prospectus qualifying the ATM program and, as a result, AQN is currently not able to issue common shares pursuant to the ATM Program.
During the three months ended December 31, 2021, the Company did not issue any common shares under its ATM Program.
During the year ended December 31, 2021, the Company issued 23,531,465 common shares under the ATM program at an average price of $15.70 per common share for gross proceeds of $369.5 million ($364.9 million net of commissions).
As at March 3, 2022, the Company has issued since the inception of the ATM program in 2019 a cumulative total of 33,952,827 common shares under the ATM program at an average price of $15.08 per share for gross proceeds of approximately $512.2 million ($505.7 million net of commissions). Other related costs, primarily related to the establishment and subsequent re-establishments of the ATM program, were $4.3 million.
Dividend Reinvestment Plan
AQN has a shareholder dividend reinvestment plan (the “Reinvestment Plan”) for registered holders of common shares of AQN. As at December 31, 2021, 127,590,058 common shares representing approximately 19% of total common shares outstanding had been registered with the Reinvestment Plan. During the three months ended December 31, 2021, 1,624,230 common shares were issued under the Reinvestment Plan, and subsequent to quarter-end, on January 14, 2022, an additional 1,625,414 common shares were issued under the Reinvestment Plan.
SHARE-BASED COMPENSATION PLANS
For the twelve months ended December 31, 2021, AQN recorded $8.4 million in total share-based compensation expense as compared to $24.6 million for the same period in 2020. The compensation expense is recorded as part of administrative expenses in the consolidated statement of operations, except for $12.6 million in 2020 related to management succession and executive retirement expenses recorded in other net losses. The portion of share-based compensation costs capitalized as cost of construction is insignificant.
As at December 31, 2021, total unrecognized compensation costs related to non-vested share-based awards was $17.1 million and is expected to be recognized over a period of 1.67 years.
Stock Option Plan
AQN has a stock option plan that permits the grant of share options to officers, directors, employees and selected service providers. Except in certain circumstances, the term of an option shall not exceed ten (10) years from the date of the grant of the option.
AQN determines the fair value of options granted using the Black-Scholes option-pricing model. The estimated fair value of options, including the effect of estimated forfeitures, is recognized as an expense on a straight-line basis over the options’ vesting periods while ensuring that the cumulative amount of compensation cost recognized at least equals the value of the vested portion of the award at that date. During the twelve months ended December 31, 2021, the Company granted 437,006 options to executives of the Company. The options allow for the purchase of common shares at a weighted average price of C$19.64, the market price of the underlying common share at the date of grant. During the twelve months ended December 31, 2021, executives and former executives of the Company exercised 506,926 stock options at a weighted average exercise price of C$13.92 in exchange for 108,128 common shares issued from treasury and 398,798 options were settled at their cash value as payment for the exercise price and tax withholdings related to the exercise of the options.
As at December 31, 2021, a total of 2,040,528 options were issued and outstanding under the stock option plan.

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Performance and Restricted Share Units
AQN issues performance share units (“PSUs”) and restricted share units ("RSUs") to certain employees as part of AQN’s long-term incentive program. During the twelve months ended December 31, 2021, the Company granted (including dividends and performance adjustments) a combined total of 805,433 PSUs and RSUs to employees of the Company. During the twelve months ended December 31, 2021, the Company settled 865,067 PSUs, of which 445,439 PSUs were exchanged for common shares issued from treasury and 419,628 PSUs were settled at their cash value as payment for tax withholdings related to the settlement of the PSUs. Additionally, during the twelve months ended December 31, 2021, a total of 217,901 PSUs were forfeited.
As at December 31, 2021, a combined total of 2,443,672 PSUs and RSUs were granted and outstanding under the PSU and RSU plans.
Directors' Deferred Share Units
AQN has a Directors' Deferred Share Unit Plan. Under the plan, non-employee directors of AQN receive all or any portion of their annual compensation in deferred share units (“DSUs”) and may elect to receive any portion of their remaining compensation in DSUs. The DSUs provide for settlement in cash or shares at the election of AQN. As AQN does not expect to settle the DSUs in cash, these DSUs are accounted for as equity awards. During the twelve months ended December 31, 2021, the Company issued 73,467 DSUs (including DSUs in lieu of dividends) to the directors of the Company. During the twelve months ended December 31, 2021, the Company settled 87,582 DSUs, of which 40,786 DSUs were exchanged for common shares issued from treasury and 46,796 DSUs were settled at their cash value as payment for tax withholdings related to the settlement of DSUs.
As at December 31, 2021, a total of 530,378 DSUs were outstanding under the DSU plan.
Bonus Deferral Restricted Share Units
The Company has a bonus deferral RSU program that is available to certain employees. The eligible employees have the option to receive a portion or all of their annual bonus payment in RSUs in lieu of cash. The RSUs provide for settlement in shares, and therefore these RSUs are accounted for as equity awards. During the twelve months ended December 31, 2021, 56,686 RSUs were issued (including RSUs in lieu of dividends) to employees of the Company. During the twelve months ended December 31, 2021, the Company settled 152,564 bonus RSUs, of which 70,571 were exchanged for common shares issued from treasury and 81,993 RSUs were settled at their cash value as payment for tax withholdings related to the settlement of the RSUs.
Employee Share Purchase Plan
AQN has an Employee Share Purchase Plan (the “ESPP”) which allows eligible employees to use a portion of their earnings to purchase common shares of AQN. The aggregate number of common shares reserved for issuance from treasury by AQN under this plan shall not exceed 4,000,000 shares. During the twelve months ended December 31, 2021, the Company issued 355,096 common shares to employees under the ESPP.
As at December 31, 2021, a total of 1,943,612 shares had been issued under the ESPP.
MANAGEMENT OF CAPITAL STRUCTURE
AQN views its capital structure in terms of its debt and equity levels at its individual operating groups and at an overall company level.
AQN’s objectives when managing capital are:
•To maintain its capital structure consistent with investment grade credit metrics appropriate to the sectors in which AQN operates;
•To maintain appropriate debt and equity levels in conjunction with standard industry practices and to limit financial constraints on the use of capital;
•To ensure capital is available to finance capital expenditures sufficient to maintain existing assets;
•To ensure generation of cash is sufficient to fund sustainable dividends to shareholders as well as meet current tax and internal capital requirements;
•To maintain sufficient liquidity to ensure sustainable dividends made to shareholders; and
•To have appropriately sized revolving credit facilities available for ongoing investment in growth and development opportunities.

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AQN monitors its cash position on a regular basis in an effort to ensure funds are available to meet current normal as well as capital and other expenditures. In addition, AQN continuously reviews its capital structure with a view to ensuring its individual business groups are using a capital structure which is appropriate for their respective industries.
RELATED PARTY TRANSACTIONS
Equity-method investments
The Company entered into a number of transactions with equity-method investees in 2021 and 2020 (see Note 8 in the annual consolidated financial statements).
The Company provides administrative and development services to its equity-method investees and is reimbursed for incurred costs. To that effect, the Company charged its equity-method investees $25.8 million in 2021, as compared to $25.7 million during the same period in 2020. Additionally, one of the equity-method investees provides development services to the Company on specified projects, for which it earns a development fee upon reaching certain milestones. During 2021, the development fees charged to the Company were $2.0 million as compared to $26.0 million during the same period in 2020. See Note 16 in the annual consolidated financial statements.
In 2020, a subsidiary of the Company made a tax equity investment into Altavista Solar Subco, LLC, an equity investee of the Company (prior to April 9, 2021) and indirect owner of the Altavista Solar Project. Following the closing of the construction financing facility for the Altavista Solar Project, certain excess funds were distributed to the Company and in return the Company issued a promissory note of $30.5 million payable to Altavista Solar Subco, LLC. The note was repaid in full during the second quarter of 2021.
In 2021, a subsidiary of the Company made a tax equity investment into New Market Solar Investco, LLC, an equity investee of the Company and indirect owner of the New Market Solar Project. Following the closing of the construction financing facility for the New Market Solar Project, certain excess funds were distributed to the Company and in return the Company issued a promissory note of $25.8 million payable to New Market Solar Investco, LLC.
In 2021, the Sandy Ridge II Wind Project, the Shady Oaks II Wind Project and the New Market Solar Project were contributed into joint venture entities in exchange for 50% equity interests in the joint ventures and loans receivable in the amount of $20.4 million and a contract asset of $17.4 million recognized for the portion of consideration payable upon mechanical completion but in no event later than December 31, 2022. The transfer of the New Market Solar Project resulted in a gain of $26.2 million.
During the third quarter of 2021, the Company paid $1.5 million to Abengoa S.A. to purchase all of Abengoa S.A.'s interests in the AAGES, AAGES Development Canada Inc., and AAGES Development Spain, S.A. joint ventures. The assets acquired for AAGES Development Spain S.A included project development assets for $2.7 million and working capital of $1.5 million. The existing loan between the Company and the partnership of $3.1 million was treated as additional consideration incurred to acquire the partnership. Pursuant to an agreement between AQN and funds managed by the Infrastructure and Power strategy of Ares Management, LLC (“Ares”), in November 2021, Ares became AQN’s new partner in its non-regulated development platform for renewable energy, water and other sectors through an investment in the AAGES and AAGES Development Canada Inc. joint ventures (collectively, the "Liberty JV").
Redeemable non-controlling interest held by related party
Redeemable non-controlling interest held by related party represents a preference share in a consolidated subsidiary of the Company acquired by AAGES in 2018 for $305.0 million (see Note 16 in the annual consolidated financial statements). Redemption is not considered probable as at December 31, 2021. The preference share was used to finance a portion of the Company's investment in Atlantica. The Company incurred non-controlling interest attributable to AAGES of $10.4 million in 2021 as compared to $12.7 million during the same period in 2020 and recorded distributions of $10.2 million in 2021 as compared to $12.2 million during the same period in 2020 (see Note 16 in the annual consolidated financial statements).
Non-controlling interest held by related party
Non-controlling interest held by related party represents interest in a consolidated subsidiary of the Company acquired by a subsidiary of Atlantica in May 2019 for $96.8 million. The interest was used to finance a portion of the Company's investment in the Amherst Island Wind Facility. During 2021 the Company recorded distributions of $17.8 million as compared to $16.1 million during the same period in 2020.
The above related party transactions have been recorded at the exchange amounts agreed to by the parties to the transactions.

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Transactions with Atlantica
During the twelve months ended December 31, 2021, the Company sold Colombian solar assets to Atlantica for consideration of approximately $23.9 million, representing the cost of the assets, and contingent consideration of approximately $2.6 million, if certain milestones are met. As at December 31, 2021, a gain on the sale of $0.9 million has been recognized.
ENTERPRISE RISK MANAGEMENT
The Corporation is subject to a number of risks and uncertainties, certain of which are described below. A risk is the possibility that an event might happen in the future that could have a negative effect on the financial condition, financial performance or business of the Corporation. The actual effect of any event on the Corporation’s business could be materially different from what is anticipated or described below. The description of risks below does not include all possible risks.
Led by the Chief Compliance and Risk Officer, the Corporation has an established enterprise risk management ("ERM") framework. The Corporation’s ERM framework follows the guidance of ISO 31000 and the Committee of Sponsoring Organizations of the Treadway Commission ("COSO") Enterprise Risk Management - Integrated Framework. The Corporation’s ERM Policy details the Corporation’s risk management processes and risk governance structure.
As part of the risk management process, risk registers have been developed across the organization through ongoing risk identification and risk assessment exercises facilitated by the Corporation’s internal ERM team. Key risks and associated mitigation strategies are reviewed by the executive-level Enterprise Risk Management Council and are presented to the Board’s Risk Committee periodically.
Identified risks are evaluated using a standardized risk scoring matrix to assess impact and likelihood. Financial, safety, security, reputational, reliability, and planned execution implications are among those considered when determining the impact of a potential risk. Risk treatment priorities are established based upon these risk assessments and incorporated into the development of the Corporation’s strategic and business plans. However, there can be no assurance that the Corporation's risk management activities will be successful in identifying, assessing, or mitigating the risks to which the Corporation is subject.
The risks discussed below are not intended as a complete list of all risks that AQN, its subsidiaries and affiliates are encountering or may encounter. Please see the Company's most recent AIF available on SEDAR and EDGAR for a further discussion of risk factors to which the Company is subject. To the extent of any inconsistency, the risks discussed below are intended to provide an update on those that were previously disclosed.
Risks Related to COVID-19
The COVID-19 situation remains fluid and its full impact on the Company’s business, financial condition, cash flows and results of operations is not fully known at this time. In addition to the risks and impacts described elsewhere in this MD&A, the COVID-19 pandemic and efforts to contain the virus could result in:
•operating, supply chain and project development and construction delays, disruptions and cost overruns;
•delayed collection of accounts receivable and increased levels of bad debt expense;
•delayed placed-in-service dates for the Company's renewable energy projects, which may give rise to, among other things, lower than anticipated revenue, delay-related liabilities to contractual counterparties and increased amounts of interest payable to construction lenders;
•reduced availability of funding under construction loans and tax equity financing, which may require the Company to initially increase its funding and, if possible, directly realize the tax benefits;
•lower revenue from the Company’s utility operations, including as a result of decreased consumption by customers not covered by rate decoupling;
•negative impacts to the Company's existing and planned rate reviews, including non-recovery of certain costs incurred directly or indirectly as a result of the COVID-19 pandemic and delays in filing, processing and settlement of the reviews;
•introduction of new legislation, policies, rules or regulations that adversely impact the Company;
•labour shortages and shutdowns (including as a result of government regulation and prevention measures), reduced employee and/or contractor productivity, and loss of key personnel;
•inability to implement the Company’s growth strategy, including sourcing new acquisitions and completing previously-announced acquisitions;

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•inability to carry out the Company’s capital expenditure plans on previously anticipated timelines;
•lower earnings from unhedged power generation as a result of lower wholesale commodity prices in energy markets;
•losses or liabilities resulting from default, delays or non-performance by either the Company or its counterparties under the Company’s contracts, including joint venture agreements, supply agreements, construction agreements, services agreements and power purchase and other offtake agreements;
•lower revenue from the Company's power generation facilities as a result of system load reduction and related system directed curtailments;
•delay in the permitting process of certain development projects, affecting the timing of final investment decisions and start of construction dates;
•reduced ability of the Company and its employees to effectively respond to, or mitigate the effects of, another force majeure or other significant event;
•increased operating costs for emergency supplies, personal protective equipment, cleaning services, enabling technology and other specific needs in response to COVID-19, some of which may not be recovered through future rates;
•increased market volatility and lower pension plan returns which could adversely impact the valuation of pension plan assets and future funding requirements for the Company's pension plans;
•deterioration in financial metrics and other factors that impact the Company’s credit ratings;
•inability to meet the requirements of the covenants in existing credit facilities;
•inability to access credit and capital markets on acceptable terms or at all, including to refinance maturing indebtedness;
•IT and operational technology system interruptions, loss of critical data and increased cybersecurity and privacy breaches due to “work from home” arrangements implemented by the Company;
•business disruptions and costs as "work from home" arrangements are reduced and a greater number of employees return to the office;
•losses to the Company caused by fluctuations and volatility in the trading price of Atlantica’s ordinary shares or reduction of the dividend paid to holders of Atlantica’s ordinary shares; and
•fluctuations and volatility in the trading price of the Company’s common shares and other securities, which could result in losses for the Company’s security holders.
The COVID-19 pandemic may also have the effect of heightening the other risks described herein, and under the heading Enterprise Risk Factors in the Company's most recent AIF. The adverse impacts of COVID-19 on the Company can be expected to increase the longer the pandemic and the related response measures persist.
Change in customer demand due to the COVID-19 Pandemic
The Company operates utility systems across 17 regulatory jurisdictions delivering electric, natural gas, water and waste water services to residential, commercial and industrial customers in the areas it serves. The COVID-19 pandemic and resulting business suspensions and shutdowns have changed consumption patterns of residential, commercial and industrial customers across all three modalities of utility services, including potential decreased consumption among certain commercial and industrial customers. Further, different regulatory jurisdictions provide different mechanisms to allow utilities to adapt to changes in demand including decoupling on a total revenue basis, decoupling on a weather adjusted basis, and fixed fee components in rates.
The Company has seen the impacts on consumption patterns reduce from their early peaks as the economy has started to re-open.
Since the length of the pandemic, any longer term economic impacts, and how these may change consumption for residential, commercial and industrial customers is not known, the full impacts on the Company’s operations are not known at this time.
Risks Related to Changes in Laws and Regulations
The operations and activities of the Company, its subsidiaries and its business units are subject to the laws, regulations, orders and other requirements of a variety of federal, state, provincial and local governments, including regulatory commissions, environmental agencies and other regulatory bodies, which laws, regulations, orders and other requirements affect the operations and activities of, and costs incurred by, the Company. The Company is accordingly subject to risks associated with changing political conditions and changes in, modifications to, or reinterpretations of, existing laws, orders

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or regulations, and the imposition of new laws, orders or regulations (including bills S6706/A7654 and S5527/A6393 adopted in the State of New York allowing the North Shore Water Authority and the South Nassau Water Authority to operate in the territories of private water companies, including the power of eminent domain, or changes being proposed to the constitution of Chile, such as changes in the water rights rules and provisions governing private ownership of water and wastewater utilities), and the taking of other action by governmental or regulatory authorities (including the revocation or non-renewal of utility franchises or other rights to provide utility services), any of which could adversely affect the Company’s business, regulatory approvals, assets, results of operations and financial condition. If the Company or any of its subsidiaries or business units were found to be in violation of such applicable laws, regulations, orders or other requirements, they could be subject to significant penalties or legal actions.
Treasury Risk Management
Downgrade in the Company's Credit Rating Risk
AQN has a long term consolidated corporate credit rating of BBB from S&P, a BBB rating from DBRS and a BBB issuer rating from Fitch. APCo, the parent company for the U.S. and Canadian generating assets under the Renewable Energy Group, has a BBB issuer rating from S&P, BBB issuer rating from DBRS and a BBB issuer rating from Fitch. Liberty Utilities, the parent company for the U.S. regulated utilities under the Regulated Services Group, has a corporate credit rating of BBB from S&P and a BBB issuer rating from Fitch. Debt issued by Liberty GP, a special purpose financing entity of Liberty Utilities, has a rating of BBB (high) from DBRS, BBB+ from Fitch and BBB from S&P. Empire has a BBB issuer rating from S&P and a Baa1 issuer rating from Moody's. Liberty Utilities (Canada) LP, the parent company for the Canadian regulated utilities under the Regulated Services Group has an issuer rating of BBB from DBRS.
The ratings indicate the agencies’ assessment of the ability to pay the interest and principal of debt securities issued by such entities. A rating is not a recommendation to purchase, sell or hold securities and each rating should be evaluated independently of any other rating. The lower the rating, the higher the interest cost of the securities when they are sold. A downgrade in AQN’s or its subsidiaries' issuer corporate credit ratings would result in an increase in AQN’s borrowing costs under its bank credit facilities and future long-term debt securities issued. Any such downgrade could also adversely impact the market price of the outstanding securities of the Company, could impact the Company's ability to acquire additional regulated utilities and could require the Company to post additional collateral security under some of its contracts and hedging arrangements. If any of AQN’s ratings fall below investment grade (investment grade is defined as BBB- or above for S&P and Fitch, BBB (low) or above for DBRS and Baa3 or above for Moody's), AQN’s ability to issue short-term debt or other securities or to market those securities would be constrained or made more difficult or expensive. Therefore, any such downgrades could have a material adverse effect on AQN’s business, cost of capital, financial condition and results of operations.
The Company is not adopting or endorsing such ratings, and such ratings do not indicate AQN’s assessment of its own ability to pay the interest or principal of debt securities it issues. The Company is providing such ratings only to assist with the assessment of future risks and effects of ratings on the Company’s financing costs.
No assurances can be provided that any of AQN's current ratings will remain in effect for any given period of time or that a rating will not be lowered or withdrawn entirely by a rating agency if, in its judgment, circumstances in the future so warrant. Each rating agency employs proprietary scoring methodologies that assess business and financial risks of the entity rated. There can be no assurance that the principles of the rating remain consistently applied, and these principles are subject to change from time to time at each rating agency’s discretion. For example, a rating agency’s views on total allowable leverage, specific industry risk factors, country risk and the company’s business mix, amongst other factors, may change. Such changes could require AQN to adjust its business and strategy in order to maintain its credit ratings. AQN currently anticipates that to continue to maintain a BBB flat investment grade credit ratings, it will, amongst other things, need to execute its growth strategy in a manner that preserves satisfaction of financial leverage targets and continues to generate more than 70% of EBITDA (as determined by applicable rating agency methodologies) from AQN’s Regulated Services Group. There can be no assurance that AQN will be successful, and the failure to do so could have a negative impact on AQN’s credit ratings. The business mix target may from time to time require AQN to grow its Regulated Services Group or implement other strategies in order to pursue investment opportunities within its Renewable Energy Group.
Capital Markets and Liquidity Risk
As at December 31, 2021, the Company had approximately $6,211.7 million of long-term consolidated indebtedness. Management of the Company believes, based on its current expectations as to the Company’s future performance, that the cash flow from its operations and funds available to it under its revolving credit facilities and its ability to access capital markets will be adequate to enable the Company to finance its operations, execute its business strategy and maintain an adequate level of liquidity. However, expected revenue and capital expenditures are only estimates. Moreover, actual cash flows from operations are dependent on regulatory, market and other conditions that are beyond the control of the Company and which may be impacted by the risk factors herein. As such, no assurance can be given that management’s expectations as to future performance will be realized.

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The ability of the Company to raise additional debt or equity or to do so on favourable terms may be adversely affected by adverse financial and operational performance, or by financial market disruptions or other factors outside the control of the Company.
In addition, the Company may at times incur indebtedness in excess of its long-term leverage targets, in advance of raising the additional equity necessary to repay such indebtedness and maintain its long-term leverage target. Any increase in the Company’s leverage could, among other things, limit the Company’s ability to obtain additional financing for working capital, investment in subsidiaries, capital expenditures, debt service requirements, acquisitions and general corporate or other purposes; restrict the Company’s flexibility and discretion to operate its business; limit the Company’s ability to declare dividends; require the Company to dedicate a portion of cash flows from operations to the payment of interest on its existing indebtedness, in which case such cash flows will not be available for other purposes; cause ratings agencies to re-evaluate or downgrade the Company’s existing credit ratings; expose the Company to increased interest expense on borrowings at variable rates; limit the Company’s ability to adjust to changing market conditions; place the Company at a competitive disadvantage compared to its competitors; make the Company vulnerable to any downturn in general economic conditions; and render the Company unable to make expenditures that are important to its future growth strategies.
The Company will need to refinance or reimburse amounts outstanding under the Company’s existing consolidated indebtedness over time. There can be no assurance that any indebtedness of the Company will be refinanced or that additional financing on commercially reasonable terms will be obtained, if at all. In the event that such indebtedness cannot be refinanced, or if it can be refinanced on terms that are less favourable than the current terms, the Company's cashflows and the ability of the Company to declare dividends may be adversely affected.
The ability of the Company to meet its debt service requirements will depend on its ability to generate cash in the future, which depends on many factors, including the financial performance of the Company, debt service obligations, the realization of the anticipated benefits of acquisition and investment activities, and working capital and capital expenditure requirements. In addition, the ability of the Company to borrow funds in the future to make payments on outstanding debt will depend on the satisfaction of covenants in existing credit agreements and other agreements. A failure to comply with any covenants or obligations under the Company’s consolidated indebtedness could result in a default under one or more such instruments, which, if not cured or waived, could result in the termination of dividends by the Company and permit acceleration of the relevant indebtedness. If such indebtedness were to be accelerated, there can be no assurance that the assets of the Company would be sufficient to repay such indebtedness in full. There can also be no assurance that the Company will generate cash flows in amounts sufficient to pay outstanding indebtedness or to fund any other liquidity needs.
Interest Rate Risk
The Company is exposed to interest rate risk from certain outstanding variable interest indebtedness and any new credit facilities and debt issuances. Fluctuations in interest rates may also impact the costs to obtain other forms of capital.
In addition, for the Regulated Services Group, costs resulting from interest rate increases may not be recoverable in whole or in part, and “regulatory lag” may cause a time delay in the payment to the Regulated Services Group of any such costs that are recoverable. Rising interest rates may also negatively impact the economics of development projects and energy facilities, especially where project financing is being renewed or arranged.
As a result, fluctuations in interest rates could materially increase the Corporation’s financing costs, limit the Corporation’s options for financing, and adversely affect its results of operations, cash flows, key credit metrics, borrowing capacity and ability to implement its business strategy
As at December 31, 2021, approximately 86% of debt outstanding in AQN and its subsidiaries was subject to a fixed rate of interest and as such is not subject to significant interest rate risk in the short to medium term time horizon.
Borrowings subject to variable interest rates can vary significantly from month to month, quarter to quarter and year to year. AQN does not actively manage interest rate risk on its variable interest rate borrowings due to the primarily short term and revolving nature of the amounts drawn.
Based on amounts outstanding as at December 31, 2021, the impact to interest expense from changes in interest rates are as follows:
•the Corporate Credit Facility is subject to a variable interest rate and had $289.9 million outstanding as at December 31, 2021. As a result, a 100 basis point change in the variable rate charged would impact interest expense by $2.9 million annually;
•the Regulated Services Credit Facility is subject to a variable interest rate and had no amounts outstanding as at December 31, 2021. As a result, a 100 basis point change in the variable rate charged would not impact interest expense;

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•the Regulated Services Delayed Draw Term Facility is subject to a variable interest rate and had no amounts outstanding as at December 31, 2021. As a result, a 100 basis point change in the variable rate charged would not impact interest expense;
•the BELCO Credit Facility is subject to a variable interest rate and had $64.3 million outstanding as at December 31, 2021. As a result, a 100 basis point change in the variable rate charged would impact interest expense by $0.6 million annually;
•the Regulated Services Group's commercial paper program is subject to a variable interest rate and had $338.7 million outstanding as at December 31, 2021. As a result, a 100 basis point change in the variable rate charged would impact interest expense by $3.4 million annually;
•the Renewable Energy Credit Facility is subject to a variable interest rate and had $14.6 million outstanding as at December 31, 2021. As a result, a 100 basis point change in the variable rate charged would impact interest expense by $0.1 million annually; and
•term facilities at BELCO and ESSAL that are subject to variable interest rates had $142.0 million outstanding as at December 31, 2021. As a result, a 100 basis point change in the variable rate charged would impact interest expense by $1.4 million annually.
Subsequent to quarter-end on January 13, 2022, the Company entered into a forward starting swap to fix the interest rate for the second five-year term of the U.S. Notes .
Foreign Currency Risk
The functional currency of most of AQN's operations is the U.S. dollar, however AQN is exposed to currency fluctuations from its Canadian and Chilean operations.
AQN may enter into derivative contracts to hedge all or a portion of currency exchange rate exposure that is transactional in nature and where a natural economic hedge does not exist (see Note 24 (b)(iii) in the annual consolidated financial statements). To the extent that the Company does enter into currency hedges, the Company may not realize the full benefits of favourable exchange rate movement, and is subject to risks that the counterparty to the hedging contracts may prove unable or unwilling to perform their obligations under the contracts.
Canadian operations
The Company is exposed to currency fluctuations from its Canadian-based operations. AQN manages this risk primarily through the use of natural hedges by using long-term debt in Canadian Dollars to finance its Canadian operations and a combination of foreign exchange forward contracts and spot purchases.
Chilean operations
The Company is exposed to currency fluctuations from its Chilean-based operations. AQN manages this risk primarily through the use of natural hedges by using long-term debt in Chilean pesos or indexed to the Chilean Peso to finance its Chilean operations. The Company's Chilean operations are determined to have the Chilean peso as their functional currency.
Tax Risk and Uncertainty
The Corporation is subject to income and other taxes primarily in the United States and Canada; however, it is also subject to income and other taxes in international jurisdictions, such as Chile and Bermuda. Changes in tax laws or interpretations thereof in the jurisdictions in which the Corporation does business could adversely affect the Company's results from operations, returns to shareholders, and cash flows. One or more taxing jurisdictions could seek to impose incremental or new taxes on the Company pursuant to one of the following or otherwise:
•While the U.S. Congress has drafted significant tax legislative proposals that include a minimum tax, additional interest limitations, and extension of clean energy tax credits, it is unknown when legislation incorporating these proposals could be enacted.
•On April 19, 2021, the Canadian federal government delivered its 2021 budget which contained proposed measures related to limitations on interest deductibility and changes in relation to international taxation. Draft legislative proposals pertaining to interest deductibility and other matters were released for public comment on February 4, 2022. The Corporation is currently reviewing the legislative proposals to determine the impact to the Corporation. If the proposed legislation becomes enacted, the interest deductibility limitations are expected to apply to the Corporation beginning in 2023.
•As a consequence of the Organization for Economic Cooperation and Development’s (“OECD”) project on “Base Erosion and Profit Shifting”, there could be a focus by taxing authorities to pursue common international principles for the entitlement to taxation of global corporate profits and minimum global tax rates. In December 2021, the OECD released model legislation outlining how a global minimum tax would apply. Each local

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jurisdiction will need to draft their own legislation to enact these minimum tax rules with application expected no earlier than January 1, 2023.
The Corporation cannot provide assurance that the Canada Revenue Agency, the Internal Revenue Service or any other applicable taxation authority will agree with the tax positions taken by the Corporation, including with respect to claimed expenses and the cost amount of the Corporation’s depreciable properties. A successful challenge by an applicable taxation authority regarding such tax positions could adversely affect the results of operations and financial position of the Corporation.
Development by the Corporation of renewable power generation facilities in the United States depends in part on federal tax credits and other tax incentives. These credits are currently subject to a multi-year step-down. While recently enacted U.S. tax reform legislation did extend some of the credits, at reduced levels, for solar facilities that begin construction in 2021, 2022 and 2023 and for wind facilities that began construction in 2021, there can be no assurance that there will be further extensions in the future or that the reduced credits will be sufficient to support continued development and construction of renewable power facilities in the United States. Moreover, if the Corporation is unable to complete construction on current or planned projects on anticipated schedules, the reduced incentives may be insufficient to support continued development or may result in substantially reduced financial benefits from facilities or long-term investment in facilities that the Corporation is committed to complete. In addition, the Corporation has entered into certain tax equity financing transactions with financial partners for certain of its renewable power facilities in the United States, under which allocations of future cash flows to the Corporation from the applicable facility could be adversely affected in the event that there are changes in U.S. tax laws that apply to facilities previously placed in service.
Credit/Counterparty Risk
AQN and its subsidiaries, through long term PPAs, trade receivables, derivative financial instruments and short term investments, are subject to credit risk with respect to the ability of customers and other counterparties to perform their obligations to the Company and its subsidiaries.
The Renewable Energy Group's revenues are approximately 12% of total Company revenues with the majority earned from large utility customers having a credit rating of Baa2 or better by Moody's, or BBB or higher by S&P, or BBB or higher by DBRS.
The remaining revenue of the Company is primarily earned by the Regulated Services Group.
The credit risk attributed to the Regulated Services Group's accounts receivable balances at the water and wastewater distribution systems total $57.9 million which is spread over approximately 413,000 customer connections, resulting in an average outstanding balance of approximately $140 dollars per customer connection.
The natural gas distribution systems accounts receivable balances related to the natural gas utilities total $119.8 million, while electric distribution systems accounts receivable balances related to the electric utilities total $125.4 million. The natural gas and electrical utilities both derive over 85% of their revenue from residential customers and have a per customer connection average outstanding balance of $321 dollars and $409 dollars respectively.
Adverse conditions in the energy industry or in the general economy including the effects of the COVID-19 pandemic, as well as circumstances of individual customers or counterparties, may adversely affect the ability of a customer or counterparty to perform as required under its contract with the Company. Losses from a utility customer may not be offset by bad debt reserves approved by the applicable utility regulator. If a customer under a long-term PPA with the Renewable Energy Group is unable to perform, the Renewable Energy Group may be unable to replace the contract on comparable terms, in which case sales of power (and, if applicable, RECs and ancillary services) from the facility would be subject to market price risk and may require refinancing of indebtedness related to the facility or otherwise have a material adverse effect. Default by other counterparties, including counterparties to hedging contracts that are in an asset position and to short-term investments, also could adversely affect the financial results of the Corporation.
Market Price Risk
The Renewable Energy Group assets subject to long term PPAs are not exposed to market risk for this portion of its portfolio. Where a generating asset is not covered by a PPA, the Renewable Energy Group may seek to mitigate market risk exposure by entering into financial or physical power hedges requiring that a specified amount of power be delivered at a specified time in return for a fixed price. There is a risk that there is a difference between the pricing at the location where power is delivered and where the hedge settles, known as basis risk, resulting in earnings volatility for the Company. To mitigate basis risk, the Company seeks to enter into additional financial contracts in order to fix the price of basis. There is a risk that the Company is not able to generate the specified amount of power at the specified time resulting in production shortfalls under the hedge that then requires the Company to purchase power in the merchant market. To mitigate the risk of production shortfalls under hedges, the Renewable Energy Group generally seeks to structure hedges to cover less than 100% of the anticipated production, thereby reducing the risk of not producing the minimum hedge quantities. Nevertheless, due to unpredictability in the natural resource or due to grid curtailments or mechanical failures, production shortfalls may be such that the Renewable Energy Group may still be forced to purchase power in the merchant market at

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prevailing rates to settle against a hedge. Any event that restricts production increases shortfall risk. Events that can reduce production include (but are not limited to) weather events (such as icing, low wind resource, cloud cover), transmission outages and mechanical failure.
Hedges currently put in place by the Renewable Energy Group for its operating facilities along with residual exposures to the market are detailed below:
The Senate, Sandy Ridge and Minonk Wind Facilities have entered into financial hedges that end between 2027 and 2028. The financial hedges are structured to hedge an average of approximately 60% of annual LTAR against exposure to the applicable hub current spot market rates. The average unhedged production based on LTAR is approximately 548 GW-hrs annually.
The Sugar Creek Wind Facility has a financial hedge in place until the end of 2030 which is structured to hedge an average of 73% of annual LTAR against exposure to the applicable hub current spot market rates. The average unhedged production based on LTAR is approximately 200 GW-hrs annually.
The Maverick Creek Wind Facility has unit contingent PPAs until the end of 2031 which are structured to hedge an average of 76% of annual LTAR against exposure to the applicable hub current spot market rates. The annual average unhedged production based on LTAR is approximately 466 GW-hrs annually.
Under each of the above noted hedges, if production is not sufficient to meet the unit quantities under the hedge, the shortfall must be purchased in the open market at market rates. The effect of this risk exposure could be material. The Renewable Energy Group tries to manage this risk by forecasting shortfalls and entering into offsetting transactions (buy back). However, the existence and extent of any shortfall cannot always be predicted.
In addition to the above noted hedges, from time to time the Renewable Energy Group enters into short-term derivative contracts (usually with terms of one to three months) to further mitigate market price risk exposure due to production variability. As at December 31, 2021, the Renewable Energy Group had entered into hedges with a cumulative notional quantity of 173,350 MW-hrs.
The Company has elected the fair value option under ASC 825, Financial Instruments to account for its investment in Atlan tica, with changes in fair value reflected in the annual consolidated statement of operations. As a result, each dollar change in the traded price of Atlantica shares will correspondingly affect the Company's net earnings by approximately $44 million.
Commodity Price Risk
The Regulated Services Group is exposed to energy and natural gas price risks at its electric and natural gas systems. The Renewable Energy Group's exposure to commodity prices is primarily limited to exposure to natural gas price risk. In this regard, a representative discussion of these risks is set out as follows:
Regulated Services Group
The CalPeco Electric System provides electric service to the Lake Tahoe California basin and surrounding areas at rates approved by the California Public Utilities Commission ("CPUC"). The CalPeco Electric System purchases the energy, capacity, and related service requirements for its customers from NV Energy via a PPA at rates reflecting NV Energy’s system average costs.
The CalPeco Electric System's tariffs allow for the pass-through of energy costs to its rate payers on a dollar for dollar basis, through the Energy Cost Adjustment Clause ("ECAC") mechanism, which allows for the recovery or refund of changes in energy costs that are caused by the fluctuations in the price of fuel and purchased power. On a monthly basis, energy costs are compared to the CPUC approved base tariff energy rates and the difference is deferred to a balancing account. Annually, based on the balance of the ECAC balancing account, if the ECAC revenues were to increase or decrease by more than 5%, the CalPeco Electric System's ECAC tariff allows for a potential adjustment to the ECAC rates which would eliminate the risk associated with the fluctuating cost of fuel and purchased power.
The Granite State Electric System is an open access electric utility allowing for its customers to procure commodity services from competitive energy suppliers. For those customers that do not choose their own competitive energy supplier, Granite State Electric System provides a Default Service offering to each class of customers through a competitive bidding process. This process is undertaken semi-annually for all Default Service customers. The winning bidder is obligated to provide a full requirements service based on the actual needs of the Granite State Electric System’s Default Service customers. Since this is a full requirements service, the winning bidder(s) take on the risk associated with fluctuating customer usage and commodity prices. The supplier is paid for the commodity by the Granite State Electric System which in turn receives pass-through rate recovery through a formal filing and approval process with the NHPUC on a semi-annual basis. The Granite State Electric System is only committed to the winning Default Service supplier(s) after approval by the NHPUC so that there is no risk of commodity commitment without pass-through rate recovery.

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The EnergyNorth Natural Gas System purchase pipeline capacity, storage and commodity from a variety of counterparties. The EnergyNorth Natural Gas System's portfolio of assets and its planning and forecasting methodology are commonly approved periodically by the NHPUC through Least Cost Integrated Resource Plan filings which typically are filed bi-annually but can be as long as a five-year interim period depending on the length of the review process. In addition, EnergyNorth Natural Gas System files with the NHPUC for recovery of its transportation and commodity costs on an annual basis through the Cost of Gas ("COG") filing and approval process. The EnergyNorth Natural Gas System establishes rates for its customers based on the NHPUC's approval of its filed COG. These rates are designed to fully recover its anticipated transportation and commodity costs. In order to minimize commodity price fluctuations, the EnergyNorth Natural Gas System locks in a fixed price basis for approximately 16% of its normal winter period purchases under a NHPUC approved hedging program. All costs associated with the fixed basis hedging program are allowed to be a pass-through to customers through the COG filing and the approved rates in said filing. Should commodity prices increase or decrease relative to the initial annual COG rate filing, the EnergyNorth Natural Gas System has the right to automatically adjust its COG rates going forward up to 25% in order to minimize any under or over collection of its gas costs. In addition, any under collections may be carried forward with interest to the next year’s corresponding COG period (i.e. winter to winter and summer to summer).
The Midstates Gas and Empire Gas Systems purchases pipeline capacity, storage and commodity from a variety of counterparties, and file with the individual state commissions for recovery of their respective transportation and commodity costs through an annual Purchase Gas Adjustment (“PGA”) filing and approval process. The Midstates Gas Systems serves customers in Missouri, Illinois and Iowa and establishes rates for its customers within the PGA filing in each state and these rates are designed to fully recover its anticipated transportation, storage and commodity costs. In order to minimize commodity price fluctuations, the Midstates Gas System has implemented a commodity hedging program, consistent with regulator expectations and approvals, designed to hedge approximately 25-50% of its non-storage related commodity purchases. All gains and losses associated with the hedging program are allowed to be a pass-through to customers through the PGA filing and are embedded in the approved rates in said filing. Rates can be adjusted on a monthly or quarterly basis in order to account for any commodity price increase or decrease relative to the initial PGA rate, minimizing any under or over collection of its gas costs. Similar to the Midstates Gas System, the Empire Gas System serves customers in Missouri, and also implements a commodity hedging program designed to hedge 70% to 90% of its winter demand inclusive of storage volumes withdrawn during the winter period. All related costs are embedded in approved rates and allowed to be a pass through to customers in the PGA. The Empire Gas System is permitted to file an Actual Cost Adjustment (“ACA”) once a year which also includes a PGA filing. In addition to the ACA filing, three more optional PGA filings are allowed during the year. The Empire Gas System’s ACA year is from September 1 to August 31 for each year.
The Peach State Gas System purchases pipeline capacity, storage and commodity from a variety of counterparties, and files with the Georgia Public Service Commission ("PSC") for recovery of its transportation, storage and commodity costs through a monthly PGA filing process. The Peach State Gas System establishes rates for its customers within the PGA filings and these rates are designed to fully recover its anticipated transportation, storage and commodity costs. In order to minimize commodity price fluctuations, the annual Gas Supply Plan filed by the Company and approved by the Georgia PSC includes a commodity hedging program designed to hedge approximately 30% of its non-storage related commodity purchases during the winter months. All gains and losses associated with the hedging program are passed through to customers in the PGA filings and are embedded in the approved rates in such filings. Rates can be adjusted on a monthly basis in order to account for any differences in gas costs relative to the amounts assumed in the PGA filings, minimizing any under or over collection of its gas costs.
The Empire Electric System’s natural gas procurement program for electrical generation is designed to manage costs to mitigate volatile natural gas prices. The Empire Electric System periodically enters into fixed price contracts with counterparties to hedge future natural gas prices in an attempt to lessen the volatility in fuel expenditures. Generally, the over/under variances associated with the hedging program are passed through to customers in the fuel adjustment clause assuming they are deemed to be prudently incurred.
BELCO purchases Heavy Fuel Oil (HFO), Light Fuel Oil (LFO) and diesel which are transported and stored in facilities in Bermuda until such time as they are delivered and consumed in its electricity generation operations. While the cost of this fuel is included in traditional rate filings through a Fuel Adjustment Rate (“FAR”), the variability in the commodity pricing has led the Regulatory Authority of Bermuda to establish a quarterly reconciliation and adjustment to the FAR. This filing evaluates current commodity pricing and usage as well as projected commodity pricing to develop the FAR for the upcoming quarter. Additionally, BELCO has periodically used hedging to lock in commodity rates in an effort to reduce pricing volatility and protect customer rates.
Renewable Energy Group
The Sanger Thermal Facility’s offtake agreement includes provisions which reduce its exposure to natural gas price risk. In this regard, a $1.00 increase in the price of natural gas per MMBTU, based on expected production levels, would result in a decrease in net revenue by approximately $0.03 million on an annual basis.

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The Windsor Locks Thermal Facility’s offtake agreement includes provisions which reduce its exposure to natural gas price risk but has exposure to market rate conditions for sales above those to its primary customer. In this regard, a $1.00 increase in the price of natural gas per MMBTU, based on expected production levels, would result in a decrease in net revenue by approximately $0.42 million on an annual basis.
The Maritime region provides short-term energy requirements to various customers at fixed rates. The energy requirements of these customers are estimated at approximately 200,000 MW-hrs in fiscal 2022, of which 190,000 MW-hrs is presently contracted. While the Tinker Hydro Facility is expected to provide the majority of the energy required to service these customers, the Maritime region anticipates having to purchase approximately 67,000 MW-hrs of its energy requirements at the ISO-NE spot rates to supplement self-generated energy should the Maritime region not be able to reach the estimated 200,000 MW-hrs. The risk associated with the expected market purchases of 67,000 MW-hrs is mitigated through the use of financial energy hedge contracts which cover approximately 11,000 MW-hrs of the Maritime region's anticipated purchases during the year at an average rate of approximately $40 per MW-hr.
OPERATIONAL RISK MANAGEMENT
Mechanical and Operational Risks
AQN's profitability could be impacted by, among other things, equipment failure, the failure of a major customer to fulfill its contractual obligations, reductions in average energy prices, a strike or lock-out at a facility, natural disasters, diseases (including COVID-19) and other force majeure events, interruption in supply chain and expenses related to claims or clean-up to adhere to environmental and safety standards.
The Regulated Services Group's water and wastewater distribution systems operate under pressurized conditions within pressure ranges approved by regulators. Should a water distribution network become compromised or damaged, the resulting release of pressure could result in serious injury or death to individuals or damage to other property.
The Regulated Services Group's electric distribution systems are subject to storm events, usually winter storm events, whereby power lines can be brought down, with the attendant risk to individuals and property. Wildfires may occur within the Regulated Services Group’s electric distribution service territories, including, without limitation, in California and the southern United States, such as the Mountain View fire that occurred on November 17, 2020, within the CalPeco Electric System’s service territory in California. In forested areas, trees falling on and lightning strikes to, distribution lines or equipment, can ignite wildfires which may pose a risk to life and property. If the Company is accused or found to be responsible for such a fire, the Company could suffer costs, losses and damages, including inverse condemnation, all or some of which may not be recoverable through insurance, legal, regulatory recovery and other processes.
The Regulated Services Group's natural gas distribution systems are subject to risks which may lead to fire and/or explosion which may impact life and property. Risks include third party damage, compromised system integrity, type/age of pipelines, and severe weather events.
The Renewable Energy Group's hydro assets utilize dams to pond water for generation and if the dams fail/breach potentially catastrophic amounts of water would flood downriver from the facility. The dams can be subjected to drought conditions and lose the ability to generate during peak load conditions, causing the facilities to fall short of either hedged or PPA committed production levels. The risks of the hydro facilities are mitigated by regular dam inspections and a maintenance program of the facility to lessen the risk of dam failure.
The Renewable Energy Group's assets could catch on fire and, depending on the season, could ignite significant amounts of forest or crop downwind from the wind farms. The wind units could also be affected by large atmospheric conditions, which could lower wind levels below the Company's PPA and hedge minimum production levels. The wind units can experience failures in the turbine blades or in the supporting towers. Production risks associated with the wind turbine generators failures is mitigated by properly maintaining the units, using long term maintenance agreements with the turbine O&Ms which provide for regular inspections and maintenance of property, and liability insurance policies.
The Renewable Energy Group's Thermal Energy Division uses natural gas and oil, and produces exhaust gases, which if not properly treated and monitored could cause hazardous chemicals to be released into the atmosphere. The units could also be restricted from purchasing gas/oil due to either shortages or pollution levels, which could hamper output of the facility. The mechanical and operational risks at the thermal facilities are mitigated through the regular maintenance of the boiler system, and by continual monitoring of exhaust gases. Fuel restrictions can be hedged in part by long term purchases.
All of the Renewable Energy Group's electric generating stations are subject to mechanical breakdown. The risk of mechanical breakdown is mitigated by properly maintaining the units and by regular inspections.
These risks are mitigated through the diversification of AQN’s operations, both operationally and geographically, the use of regular maintenance programs, including pipeline safety programs and compliance programs, maintaining adequate insurance, an active Enterprise Risk Management program and the establishment of reserves for expenses.

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Regulatory Risk
Profitability of AQN businesses is, in part, dependent on regulatory climates in the jurisdictions in which those businesses operate. In the case of some of Renewable Energy Group's hydroelectric facilities, water rights are generally owned by governments that reserve the right to control water levels, which may affect revenue.
The Regulated Services Group’s facilities are subject to rate setting by its regulatory agencies. The Regulated Services Group operates in 13 U.S. states, one Canadian province, Bermuda and Chile and therefore is subject to regulation from 17 different regulatory agencies including FERC. The time between the incurrence of costs and the granting of the rates to recover those costs by regulatory agencies is known as regulatory lag. As a result of regulatory lag, inflationary effects and timing delays may impact the ability to recover expenses and/or capital costs, and profitability could be impacted. In order to mitigate this exposure, the Regulated Services Group seeks to obtain approval for regulatory constructs in the states in which it operates to allow for timely recovery of operating expenses and capital costs. A fundamental risk faced by any regulated utility is the disallowance of operating expenses or capital costs to be placed into its revenue requirement by the utility's regulator. In addition, capital investments that have become stranded may pose additional risk for cost recovery and could be subject to legislative proposals that would impact the extent to which such costs could be recovered. To the extent proposed costs are not included in the utility's revenue requirement, the utility will be required to find other efficiencies, growth opportunities or cost savings to achieve its allowed returns.
The Regulated Services Group regularly works with its governing authorities to manage the affairs of the business, employing both local, state level, and corporate resources.
Condemnation Expropriation Proceedings
The Regulated Services Group's distribution systems could be subject to condemnation or other methods of taking by government entities under certain conditions. Any taking by government entities would legally require fair compensation to be paid. Determination of such fair compensation is undertaken pursuant to a legal proceeding and, therefore, there is no assurance that the value received for assets taken will be in excess of book value.
Inflation Risk
AQN's profitability could be impacted by inflation increases above long-term averages. The Regulated Services Group’s facilities are subject to rate setting by its regulatory agencies. The time between the incurrence of costs and the granting of the rates to recover those costs by regulatory agencies is known as regulatory lag. As a result of regulatory lag, inflationary effects and timing delays may impact the ability to recover expenses and/or capital costs, and profitability could be impacted. In the event of significant inflation, the impact of regulatory lag on the Company would be increased. In order to mitigate this exposure, the Regulated Services Group seeks to obtain approval for regulatory constructs in the states in which it operates to allow for timely recovery of operating expenses and capital costs.
The Renewable Energy Group's assets subject to long term PPAs, some of which are not indexed to inflation and could experience declines in profitability if operating costs increase at a rate greater than the offtake price.
Development and construction projects could experience a decrease in expected returns as a result of increased costs. To mitigate the risk of inflation the Company attempts to enter into fixed price constructions agreements and fixed price offtake agreements.
Risks Relating to the Kentucky Power Transaction
The closing of the Kentucky Power Transaction is subject to the normal commercial risks that such acquisition will not close on the terms negotiated or at all. The Kentucky Power Transaction remains subject to closing conditions, including certain regulatory and governmental approvals. The failure to satisfy or waive the conditions may result in the termination of the acquisition agreement. Accordingly, there can be no assurance that the Company will complete the Kentucky Power Transaction in the timeframe or on the basis described herein, if at all. As the Kentucky Power Transaction is subject to various regulatory approvals, it is consequently subject to the risks that such approvals may not be timely obtained or may impose unfavourable conditions that could impair the ability to complete the acquisition or impose adverse conditions on the Company in order to complete the acquisition. The presence of intervenors in the regulatory approval process has the effect of increasing these risks.
If the Kentucky Power Transaction is not completed, the Company could be subject to a number of risks that may adversely affect the Company’s business, financial condition, results of operations, reputation and cash flows, including (i) the requirement to pay costs relating to the Kentucky Power Transaction, including costs relating to the financing thereof and obtaining regulatory approval, (ii) the requirement to find effective new uses for the net proceeds of the Company’s Common Equity Offering and Note Offerings, and (ii) time and resources committed by the Company’s management to matters relating to the Kentucky Power Transaction that could otherwise have been devoted to pursuing other beneficial opportunities. In addition, if the acquisition agreement for the Kentucky Power Transaction is terminated in certain circumstances, the Company may be required to pay a termination fee of $65 million. See “Significant Updates”.

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Business combinations such as the Kentucky Power Transaction involve risks that could materially and adversely affect the Company’s business plan, including the failure to realize the results that the Company expects. There can be no assurance that the Company will be successful in increasing the historical returns earned by either of Kentucky Power or Kentucky Transco, that the load declines experienced by Kentucky Power over recent years will not continue to be a prevailing trend, or that the Company will be able to fully realize some or all of the expected benefits of the Kentucky Power Transaction or succeed in implementing its strategic objectives relating to the acquired entities, including the transfer of operational control of the Mitchell Plant from Kentucky Power to the Wheeling Power Company and the transition of Kentucky Power’s generating mix to greener sources (i.e. “greening the fleet” initiatives). The ability to realize these anticipated benefits and implement these strategic objectives will depend in part on successfully retaining staff, hiring additional staff to replace certain of the vendors’ centralized operations, obtaining favourable regulatory outcomes, realizing growth opportunities, no unanticipated economic changes in the areas where the acquired entities operate, and potential synergies through the coordination of activities and operations with the Company’s existing business. There is a risk that some or all of the expected benefits and strategic objectives will fail to materialize, or may not occur within the time periods anticipated by the Company. A failure to realize the anticipated benefits of or implement strategic objectives relating to the Kentucky Power Transaction on an efficient and effective basis could have a material adverse effect on the Company’s financial condition, results of operations, reputation and cash flows.
A change in the capital structure of the Company could cause credit rating agencies which rate the Company’s outstanding debt obligations to re-evaluate and potentially downgrade the Company’s current credit ratings, which could increase the Company’s borrowing costs and adversely impact the market price of the outstanding securities of the Company. See “Capital Markets and Liquidity Risk”.
The Kentucky Power Transaction could also result in a downgrade of the credit rating of Kentucky Power or its outstanding bonds, and could require Kentucky Power to offer to prepay $525 million in principal amount of its outstanding bonds if the credit ratings thereof fall below investment grade (or in the event such bonds are placed on “credit watch” or assigned a “negative outlook” if they are rated BBB- by S&P or Baa3 by Moody’s at such time).
There may be liabilities that the Company failed to discover or was unable to quantify in the Company’s due diligence, and the Company may not have recourse for some or all of these potential liabilities. While the Company has accounted for these potential liabilities for the purposes of making its decision to enter into the acquisition agreement, there can be no assurance that any such liability will not exceed the Company’s estimates. In connection with the Kentucky Power Transaction, the Company has obtained a representation and warranty insurance policy, with coverage up to $255 million, subject to an initial retention of $21 million. Nevertheless, this insurance policy is subject to certain exclusions and limitations and there may be circumstances for which the insurer attempts to limit such coverage or refuses to indemnify the Company or where the coverage provided under the insurance policy may otherwise be insufficient or inapplicable.
Kentucky Power and Kentucky Transco may be a party to agreements that contain change of control and/or termination for convenience provisions which may be triggered following completion of the Kentucky Power Transaction. The operation of these change of control or termination provisions, if triggered, could result in unanticipated expenses and/or cash payments following the consummation of the Kentucky Power Transaction or adversely affect the acquired entities’ results of operations and financial condition. Unless these change of control provisions are waived, or the termination provisions are not exercised, by the other party, the operation of any of these provisions could adversely affect the results of operations and financial condition of the Company and the acquired entities.
All of the electricity generated by Kentucky Power is produced by the combustion of fossil fuels. As a result, the acquisition of Kentucky Power could result in reputational harm to the Company and adversely affect perceptions regarding the Company’s commitment to environmental and sustainability matters, as well as the Company’s ability to accomplish its environmental and sustainability objectives. The operation of fossil-fueled generation plants, including resulting emissions of nitrogen and sulfur oxides, mercury and particulates and the discharge and disposal of solid waste (including coal-combustion residuals (“CCRs”)), is subject to extensive federal, state and local environmental statutes, rules and regulations relating to air quality, water quality, waste management, natural resources and health and safety. Compliance with these requirements requires Kentucky Power to incur significant costs, including capital expenditures, for environmental monitoring, installation of pollution control equipment, emission fees, disposal activities, decommissioning, and permitting obligations at its facilities. If these compliance costs become uneconomical, Kentucky Power may ultimately be required to retire generating capacity prior to the end of its estimated life. The costs of complying with these legal requirements could also adversely affect Kentucky Power’s results of operations, financial condition and cash flows, and those of the Company following the closing of the Kentucky Power Transaction. In addition, the impacts could become even more significant if existing requirements governing air emissions management and disposal, CCR waste and/or waste matter discharge become more restrictive in the future, more extensive operating and/or permitting requirements are imposed or additional substances associated with power generation are subjected to increased regulation. Although Kentucky Power typically recovers expenditures for pollution control technologies, replacement generation, undepreciated plant balances and associated operating costs from customers, there can be no assurance that Kentucky Power will be able to obtain a rate order to fully recover the remaining costs associated with such plants in the future. The failure to recover

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these costs could reduce Kentucky Power’s results of operations, financial condition and cash flows, and those of the Company following the closing of the Kentucky Power Transaction.
In addition, future changes to environmental laws, including with respect to the regulation of CO2 emissions, could cause Kentucky Power to incur materially higher costs than it has incurred to date.
International Investment Risk
The Company operates in markets, or may pursue growth opportunities in new markets, that are subject to regulation by various foreign governments and regulatory authorities and to the application of foreign laws. Such foreign laws or regulations may not provide the same type of legal certainty and rights, in connection with the Company’s contractual relationships in such countries, as are afforded to the Company in Canada and the U.S., which may adversely affect the Company’s ability to receive revenues or enforce its rights in connection with any operations or projects in such jurisdictions. In addition, the laws and regulations of some countries may limit the Company’s ability to hold a majority interest in certain projects, thus limiting the Company’s ability to control the operations of such projects. Any existing or new operations or interests of the Company may also be subject to significant political, economic and financial risks, which vary by country, and may include: (i) changes in government laws, policies or personnel or a country's constitution; (ii) changes in general economic conditions; (iii) restrictions on currency transfer or convertibility; (iv) changes in labour relations; (v) political instability and civil unrest; (vi) regulatory or other changes adversely affecting the local utility market; (vii) breach or repudiation of important contractual undertakings and expropriation and confiscation of assets and facilities without compensation or compensation that is less than fair market value; (viii) less developed or efficient financial markets than in North America; (ix) the absence of uniform accounting, auditing and financial reporting standards, practices and disclosure requirements; (x) less government supervision and regulation; (xi) a less developed legal or regulatory environment, including uncertainty in outcomes and actions that may be inconsistent with the rule of law; (xii) heightened exposure to corruption risk; (xiii) political hostility to investments by foreign investors, including laws affecting foreign ownership; (xiv) less publicly available information in respect of companies; (xv) adversely higher or lower rates of inflation; (xvi) higher transaction costs; and (xvii) fewer investor protections.
The Company may suffer a significant loss resulting from fraud, bribery, corruption or other illegal acts, or from inadequate or failed internal processes or systems. The Company operates in multiple jurisdictions and it is possible that its operations and development activities will expand into new jurisdictions. Doing business in multiple jurisdictions requires the Company to comply with the laws and regulations of such jurisdictions. These laws and regulations may apply to the Company, its subsidiaries, individual directors, officers, employees and third-party agents. The Company is also subject to anti-bribery and anti-corruption laws, including the Canadian Corruption of Foreign Public Officials Act and the U.S. Foreign Corrupt Practices Act. As the Company makes acquisitions and pursues development activities internationally, it is exposed to increased corruption-related risks, including potential violations of applicable anti-corruption laws.
The Company relies on its infrastructure, controls, systems and personnel, as well as central groups focusing on enterprise-wide management of specific operational risks such as fraud, trading, outsourcing, and business disruption, to manage the risk of illegal and corrupt acts or failed systems. The Company also relies on its employees and certain third parties to comply with its policies and processes as well as applicable laws. The failure to adequately identify or manage these risks, and the acquisition of businesses with weak internal controls to manage the risk of illegal or corrupt acts, could result in direct or indirect financial loss, regulatory censure and/or harm to the Company’s reputation.
Risks Specific to the Atlantica Investment
The Company’s investment in Atlantica exposes the Company to certain risks that are particular to Atlantica’s business and the markets in which Atlantica operates.
Atlantica owns, manages and acquires renewable energy, conventional power, electric transmission lines and water assets in certain jurisdictions where the Company may not operate. The Company, through its investment in Atlantica, is indirectly exposed to certain risks that are particular to the markets in which it operates, including, but not limited to, risks related to: conditions in the global economy; changes to national and international laws, political, social and macroeconomic risks relating to the jurisdictions in which Atlantica operates, including in emerging markets, which could be subject to economic, social and political uncertainties; anti-bribery and anti-corruption laws and substantial penalties and reputational damage from any non-compliance therewith; significant currency exchange rate fluctuations; Atlantica’s ability to identify and/or consummate future acquisitions on favourable terms or at all; Atlantica’s inability to replace, on similar or commercially favourable terms, expiring or terminated offtake agreements; termination or revocation of Atlantica’s concession agreements or PPAs; and various other factors. These risks could affect the profitability and growth of Atlantica’s business, and ultimately the profitability of the Company’s anticipated investment therein.
The Company’s international acquisition, development, construction and operating activities, including through the Liberty JV, expose the Company to similar risks and could likewise affect the profitability, financial condition and growth of the Company.

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The Company accounts for its investment in Atlantica using the Fair Value Method (see Note 8(a) in the annual consolidated financial statements). AQN records in the consolidated statements of operations the fluctuations in the fair value of Atlantica shares and dividend income when it is declared.
Joint Venture Investment Risk
The Company has, and may in the future continue to have, an equity interest of 50% or less in certain projects and facilities. As a result, the Company will not control such projects and facilities and its interest may be subject to the decision-making of third parties, and the Company may be reliant on a third party’s personnel, good faith, contractual compliance, expertise, historical performance, technical resources and information systems, proprietary information and judgment in providing the services. This may limit the Company’s flexibility and financial returns with respect to these projects and facilities, and create a risk that the Company’s joint venture partner may:
•have economic or business interests or goals that are inconsistent with the Company’s economic or business interests or goals;
•take actions contrary to the Company’s policies or objectives with respect to the Company’s investments;
•contravene applicable anti-bribery laws that carry substantial penalties for non-compliance and could cause reputational damage and a material adverse effect on the business, financial position and results of operations of the joint venture and the Company;
•have to give its consent with respect to certain major decisions, including among others, decisions relating to funding and transactions with affiliates;
•become bankrupt, limiting its ability to meet calls for capital contributions and potentially making it more difficult to refinance or sell projects;
•become engaged in a dispute with the Company that might affect the Company’s ability to develop a project;
•have competing interests in the Company’s markets that could create conflict of interest issues; or
•have different accounting policies than the Company.
The Liberty JV (through Liberty Global Energy Solutions B.V.) is a party to a secured credit facility in the amount of $306.5 million (the “Liberty JV Secured Credit Facility”) and holds a preference share ownership interest in Liberty (AY Holdings) B.V. (“AY Holdings”). The Liberty JV Secured Credit Facility is collateralized through a pledge of Atlantica ordinary shares held by AY Holdings. A collateral shortfall would occur if the net obligation (as defined in the credit agreement) would equal or exceed 50% of the market value of such Atlantica shares. In the event of a collateral shortfall, the Liberty JV is required to prepay a portion of the loan or post additional collateral in cash to reduce the net obligation to 40% of the total collateral provided (the “Collateral Reset Level”). If the Liberty JV were unable to fund the collateral shortfall, or certain other events of default occur, the Liberty JV Secured Credit Facility lenders hold the right to sell Atlantica shares to pay amounts outstanding under the facility, including reducing the facility to the Collateral Reset Level. The Liberty JV Secured Credit Facility is repayable on demand if Atlantica ceases to be a public company. If the Liberty JV were unable to repay the amounts owed, the lenders would have the right realize on their collateral.
The Company has entered into Equity Capital Contribution Agreements ("ECCA") with certain of its project development entities it holds an equity interest in. The ECCAs obligate the Company to provide funding upon the realization of certain completion milestones related to the projects under development. The ECCAs have been pledged as collateral against construction loans obtained by the project entities and may require the Company to fund in amounts in excess of the underlying value of the assets. The Company has also provided guarantees of performance for certain development projects owned by the equity investees.
Please refer to Note 8 in the annual consolidated financial statements for a description of the Company's Long Term Investments and Notes Receivable.
Dispositions
For financial, strategic and other reasons, the Company may from time to time dispose of, or desire to dispose of, businesses or assets (in whole or in part) that it owns. Such disposals may result in recognition of a loss upon such a sale. In addition, as a result of divestitures, the Company’s revenues, cash flows and net income may decrease, and its business mix may change. Further, the Company may not be able to dispose of businesses or assets that the Corporation desires to sell for financial, strategic and other business reasons at all or at a price acceptable to the Company.

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Asset Retirement Obligations
AQN and its subsidiaries complete periodic reviews of potential asset retirement obligations that may require recognition. As part of this process, AQN and its subsidiaries consider the contractual requirements outlined in their operating permits, leases, and other agreements, the probability of the agreements being extended, the ability to quantify such expense, the timing of incurring the potential expenses, as well as other factors which may be considered in evaluating if such obligations exist and in estimating the fair value of such obligations.
In conjunction with acquisitions and developed projects, the Company assumed certain asset retirement obligations. The asset retirement obligations mainly relate to legal requirements for: (i) removal or decommissioning of power generating facilities; (ii) cut (disconnect from the distribution system), purge (clean of natural gas and PCB contaminants), and cap gas mains within the gas distribution and transmission system when mains are retired in place, or dispose of sections of gas mains when removed from the pipeline system; (iii) clean and remove storage tanks containing waste oil and other waste contaminants; and (iv) remove asbestos upon major renovation or demolition of structures and facilities.
Cycles and Seasonality
Regulated Services Group
The Regulated Services Group's demand for water is affected by weather conditions and temperature. Demand for water during warmer months is generally greater than cooler months due to requirements for irrigation, swimming pools, cooling systems and other outside water use. If there is above normal rainfall or rainfall is more frequent than normal the demand for water may decrease, adversely affecting revenues.
The Regulated Services Group's demand for energy from its electric distribution systems is primarily affected by weather conditions and conservation initiatives. The Regulated Services Group provides information and programs to its customers to encourage the conservation of energy. In turn, demand may be reduced which could have short-term adverse impacts on revenues.
The Regulated Services Group's primary demand for natural gas from its natural gas distribution systems is driven by the seasonal heating requirements of its residential, commercial, and industrial customers. The colder the weather the greater the demand for natural gas to heat homes and businesses. As such, the natural gas distribution systems demand profiles typically peaks in the winter months of January and February and declines in the summer months of July and August. Year to year variability also occurs depending on how cold the weather is in any particular year.
There is a risk that climate change impacts the seasonality and demand for water, electricity and gas.
The Company attempts to mitigate the above noted risks by seeking regulatory mechanisms during rate review proceedings. While not all regulatory jurisdictions have approved mechanisms to mitigate demand fluctuations, to date, the Regulated Services Group has successfully obtained regulatory approval to implement such decoupling mechanisms in 7 of 13 states. An example of such a mechanism is seen at the Peach State Gas System in Georgia, where a weather normalization adjustment is applied to customer bills during the months of October through May that adjusts commodity rates to stabilize the revenues of the utility for changes in billing units attributable to weather patterns.
Renewable Energy Group
The Renewable Energy Group's hydroelectric operations are impacted by seasonal fluctuations and year to year variability of the available hydrology. These assets are primarily “run-of-river” and as such fluctuate with natural water flows. During the winter and summer periods, flows are generally lower while during the spring and fall periods flows are generally higher. The ability of these assets to generate income may be impacted by changes in water availability or other material hydrologic events within a watercourse. Year to year the level of hydrology varies, impacting the amount of power that can be generated in a year.
The Renewable Energy Group's wind generation facilities are impacted by seasonal fluctuations and year to year variability of the wind resource. During the fall through spring period, winds are generally stronger than during the summer periods. The ability of these facilities to generate income may be impacted by naturally occurring changes in wind patterns and wind strength.
The Renewable Energy Group's solar generation facilities are impacted by seasonal fluctuations and year to year variability in the solar radiance. For instance, there are more daylight hours in the summer than there are in the winter, resulting in higher production in the summer months. The ability of these facilities to generate income may be impacted by naturally occurring changes in solar radiance.
The Company attempts to mitigate the above noted natural resource fluctuation risks by acquiring or developing generating stations in different geographic locations.

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Development and Construction Risk
The Company actively engages in the development and construction of new power generation facilities. There is always a risk that material delays and/or cost overruns could be incurred in any of the projects planned or currently in construction affecting the Company’s overall performance. There are risks that actual costs may exceed budget estimates, delays may occur in obtaining permits and materials, suppliers and contractors may not perform as required under their contracts, there may be inadequate availability, productivity or increased cost of qualified craft labor, start-up activities may take longer than planned, the scope and timing of projects may change, and other events beyond the Company's control may occur that may materially affect the schedule, budget, cost and performance of projects. Regulatory approvals can be challenged by a number of mechanisms which vary across state and provincial jurisdictions. Such permitting challenges could identify issues that may result in permits being modified or revoked.
Risks Specific to Renewable Generation Projects:
The strength and consistency of the wind resource will vary from the estimate set out in the initial wind studies that were relied upon to determine the feasibility of the wind facility. If weather patterns change or the historical data proves not to accurately reflect the strength and consistency of the actual wind, the assumptions underlying the financial projections as to the amount of electricity to be generated by the facility may be different and cash could be impacted.
The amount of solar radiance will vary from the estimate set out in the initial solar studies that were relied upon to determine the feasibility of the solar facility. If weather patterns change or the historical data proves not to accurately reflect the strength and consistency of the solar radiance, the assumptions underlying the financial projections as to the amount of electricity to be generated by the facility may be different and cash could be impacted.
For certain of its development projects, the Company relies on financing from third party tax equity investors. These investors typically provide funding upon commercial operation of the facility. Should certain facilities not meet the conditions required for tax equity funding, expected returns from the facilities may be impacted.
Development by the Renewable Energy Group of renewable power generation facilities in the United States depends in part on federal tax credits and other tax incentives. These incentives are currently subject to a multi-year step-down. In the second quarter of 2021, the IRS extended the “continuity safe harbor” deadline by one to two years, depending on when the project was placed in service, by which wind and solar projects must be placed in service to qualify for the maximum permissible PTC and ITC, respectively. The first step down is now set to occur on December 31, 2022.
In each of the jurisdictions where the Company's major renewable energy construction projects are located, construction of new renewable energy generation has been considered an essential activity exempt from government-mandated business shutdowns. As a result, construction activities have proceeded at all of the Company's major renewable energy construction projects throughout the COVID-19 pandemic.
Since February 2020, AQN has received force majeure notices or similar notices from suppliers and/or contractors for all of its major renewable energy construction projects. Certain manufacturing, transportation, construction and delivery delays have occurred, and similar future disruptions are possible due to COVID-19. The Company expects that all of its U.S. wind and solar projects currently under construction will qualify for the maximum PTC and ITC, respectively.
Litigation Risks and Other Contingencies
AQN and certain of its subsidiaries are involved in various litigation, claims and other legal and regulatory proceedings that arise from time to time in the ordinary course of business. Any accruals for contingencies related to these items are recorded in the financial statements at the time it is concluded that a material financial loss is likely and the related liability is estimable. Anticipated recoveries under existing insurance policies are recorded when reasonably assured of recovery.
Mountain View Fire
On November 17, 2020, a wildfire now known as the Mountain View fire occurred in the territory of Liberty Utilities (CalPeco Electric) LLC ("Liberty CalPeco"). The cause of the fire is undetermined at this time, and CAL FIRE has not yet issued a report. There are currently eight active lawsuits that name the Company and/or certain of its subsidiaries as defendants in connection with the Mountain View fire. Four of these lawsuits are brought by groups of individual plaintiffs alleging causes of action including negligence, inverse condemnation, nuisance, trespass, and violations of Cal. Pub. Util. Code 2106 and Cal. Health and Safety Code 13007. In the fifth active lawsuit, County of Mono, Antelope Valley Fire Protection District, Toiyabe Indian Health Project, and Bridgeport Indian Colony allege similar causes of action and seek damages for fire suppression costs, law enforcement costs, property and infrastructure damage, and other costs. In three other lawsuits, insurance companies allege inverse condemnation and negligence and seek recovery of amounts paid and to be paid to their insureds. The likelihood of success in these lawsuits cannot be reasonably predicted. Liberty CalPeco intends to vigorously defend them. The Company has wildfire liability insurance that is expected to apply up to applicable policy limits.

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Apple Valley Condemnation Proceedings
On January 7, 2016, the Town of Apple Valley filed a lawsuit seeking to condemn the utility assets of Liberty Utilities (Apple Valley Ranchos Water) Corp. On May 7, 2021, the Court issued a Tentative Statement of Decision denying the Town of Apple Valley’s attempt to take the Apple Valley water system by eminent domain. The ruling confirmed that Liberty Apple Valley’s continued ownership and operation of the water system is in the best interest of the community. The Town filed its objections to the Tentative Decision on June 1, 2021. On October 14, 2021, the Court denied the Town’s objections and issued the Final Statement of Decision. On January 7, 2022, the Town filed a notice of appeal of the judgment entered by the Court.
Information Security Risk
The Company relies upon technology networks, systems and devices to process, transmit and store electronic information, and to manage and support a variety of business processes and activities and safely operate its assets. The Company also uses technology systems to record, process and summarize financial information and results of operations for internal reporting purposes and to comply with financial reporting, legal and tax requirements. The Company’s technology networks, systems and devices collect and store sensitive data, including system operating information, proprietary business information belonging to the Company and third parties, as well as personal information belonging to the Company’s customers and employees. As the Company operates critical infrastructure, it may be at an increased risk of cyber-attacks or other security threats by third parties.
The Company’s or its third-party vendors’ technology systems and technology networks, devices and infrastructure may be vulnerable to damage, disruptions or shutdowns due to attacks by hackers or breaches due to employee error or malfeasance, disruptions during software or hardware upgrades, telecommunication failures, theft, and politically driven acts of war or terrorism, natural disasters or other similar events. In addition, certain sensitive information and data may be stored by the Company on physical devices, in physical files and records on its premises or transmitted to the Company verbally, subjecting such information and data to a risk of loss, theft and misuse. Methods used to attack critical assets could include general purpose or industry-sector-specific malware delivered via network transfer, removable media, viruses, attachments, or links in e-mails. The methods used by attackers are continuously evolving and can be difficult to predict and detect. The occurrence of any of these events could impact the reliability of the Company’s power generation facilities and utility distribution and transmission systems; could cause services disruptions or system failures; could adversely affect safety; could expose the Company, its customers or its employees to a risk of loss or misuse of information; and could result in legal claims or proceedings, liability or regulatory penalties against the Company, damage the Company’s reputation or otherwise harm the Company’s business.
The long-term impact of terrorist attacks and cyber-attacks and the magnitude of the threat of future terrorist attacks and cyber-attacks on the utility and power generation industries in general, and on the Company in particular, cannot be known. Increased security measures to be taken by the Company as a precaution against possible terrorist attacks and cyber-attacks may result in increased costs to the Company. The Company must also comply with data privacy laws in each of the jurisdictions in which it operates. Certain data privacy laws have expanded in recent years, leading to increased obligations, and fines for breaches of privacy laws have increased. The Company may incur additional costs to maintain compliance, or significant financial penalties, in the event of a breach.
The Company cannot accurately assess the probability that a security breach may occur or accurately quantify the potential impact of such an event. The Company can provide no assurance that it will be able to identify and remedy all cybersecurity, physical security or system vulnerabilities or that unauthorized access or errors will be identified and remedied. Should a breach occur, the Company may suffer costs, losses, and damages, all or some of which may not be recoverable through insurance, legal, regulatory, or other processes, and could materially adversely affect the Company’s business and results of operations including its reputation with customers, regulators, governments, and financial markets. Resulting costs could include, amongst others, response, recovery, and remediation costs, increased protection or insurance costs, and costs arising from damages and losses incurred by third parties.
Uncertainty surrounding continued hostilities or sustained military campaigns may affect operations of the Company in unpredictable ways, including disruptions of supplies and markets for products of the Company, and the possibility that the Company’s operations or facilities could be direct targets of, or indirect casualties of, an act of terror. The effects of a terrorist or cyber-security attack could include disruption to the Company’s generation, transmission and distribution systems or to the electrical grid in general, and could result in a decline in the general economy and have a material adverse effect on the Company.

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Energy Consumption and Advancement in Technologies Risk
The Company’s generation, distribution and transmission assets are affected by energy and water demand in the jurisdictions in which they operate. That demand may change as a result of, among other things, fluctuations in general economic conditions, energy and commodity prices, employment levels, personal disposable income, customer preferences, advancements in new technologies and housing starts. Significantly reduced energy or water demand in the Company’s service territories could reduce capital spending forecasts, and specifically capital spending related to new customer growth. A reduction in capital spending could, in turn, affect the Company’s rate base and earnings growth. A severe prolonged downturn in economic conditions may have an adverse effect on the Company’s results of operations, financial condition and cash flows despite regulatory measures, where applicable, available to compensate for reduced demand. In addition, an extended decline in economic conditions could make it more difficult for customers to pay for the utility services they consume, thereby affecting the aging and collection of the utilities’ trade receivables.
The emergence of initiatives designed to reduce greenhouse gas emissions and control or limit the effects of climate change has resulted in incentives to increase energy efficiency and reduce water and energy consumption, including efforts to reduce the availability and reliance on natural gas. There may also be efforts to move to deregulation in certain of the markets in which the Regulated Services Group operates.
In addition, significant technological advancements are taking place in the generation and utility industry, including advancements related to self-generation and distributed energy technologies such as fuel cells, micro turbines, wind turbines and solar panels and technologies related to lower energy, gas and water use. Adoption of these and other technologies may increase as a result of government subsidies, improving economics and changing customer preferences.
Increased adoption of these practices, requirements and technologies could reduce demand for utility-scale power generation and electric, water, and natural gas distribution, and as result, the Company’s business, financial condition and results of operations could be adversely affected.
The Company may also invest in and use newly developed, less proven, technologies or generation methods in its development and construction projects or in maintaining or enhancing its existing operations and assets. There is no guarantee that such new technologies will perform as anticipated. The failure of a new technology or generation method to perform as anticipated may adversely affect the profitability of a particular development project or existing operations and assets.
The Regulated Services Group is actively involved in working with governments and customers in an effort to ensure these changes in consumption do not negatively impact the services provided.
Uninsured Risk
The Company maintains insurance coverage for certain exposures, but this coverage is limited and the Company is generally not fully insured against all significant losses. Insurance coverage for the Company is subject to policy conditions and exclusions, coverage limits, and various deductibles, and not all types of liabilities and losses may be covered by insurance. Further, certain assets and facilities of the Company are not fully insured, as the cost of the coverage is not economically viable. Insurance may not continue to be offered on an economically feasible basis and may not cover all events that could give rise to a loss or claim involving the Company’s assets or operations. There can also be no assurance that insurers will fulfill their obligations. The Company’s ability to obtain and maintain insurance and the terms of any available insurance coverage could be materially adversely affected by international, national, state or local events and company-specific events, as well as the financial condition of insurers.
If the Company were to incur a serious uninsured loss or a loss significantly exceeding the limits of its insurance policies, the results could have a material adverse effect on the Company’s business, results of operations, financial condition and cash flows. In the event of a large uninsured loss, including those caused by severe weather conditions, natural disasters and certain other events beyond the control of the Regulated Services Group, the Company may make an application to an applicable regulatory authority for the recovery of these costs through customer rates to offset any loss. However, the Company cannot provide assurance that the regulatory authorities would approve any such application in whole or in part. This potential recovery mechanism is not available to the Renewable Energy Group.

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QUARTERLY FINANCIAL INFORMATION
The following is a summary of unaudited quarterly financial information for the eight quarters ended December 31, 2021:

(all dollar amounts in $ millions except per share information) | 1st Quarter 2021 |  | 2nd Quarter 2021 |  | 3rd Quarter 2021 |  | 4th Quarter 2021
Revenue | $ | 634.5 |  |  | $ | 527.5 |  |  | $ | 528.6 |  |  | $ | 594.8 |
Net earnings (loss) attributable to shareholders | 13.9 |  |  | 103.2 |  |  | (27.9) |  |  | 175.6 |
Net earnings (loss) per share | 0.02 |  |  | 0.16 |  |  | (0.05) |  |  | 0.27 |
Diluted net earnings (loss) per share | 0.02 |  |  | 0.16 |  |  | (0.05) |  |  | 0.26 |
Adjusted Net Earnings 1 | 124.5 |  |  | 91.7 |  |  | 97.6 |  |  | 136.3 |
Adjusted Net Earnings per common share 1 | 0.20 |  |  | 0.15 |  |  | 0.15 |  |  | 0.21 |
Adjusted EBITDA 1 | 282.9 |  |  | 244.9 |  |  | 252.0 |  |  | 297.6 |
Total assets | 15,286.1 |  |  | 16,453.7 |  |  | 16,699.0 |  |  | 16,785.8 |
Long term debt 2 | 6,353.7 |  |  | 6,622.6 |  |  | 6,870.3 |  |  | 6,211.7 |
Dividend declared per common share | $ | 0.16 |  |  | $ | 0.17 |  |  | $ | 0.17 |  |  | $ | 0.17 |
| 1st Quarter 2020 |  | 2nd Quarter 2020 |  | 3rd Quarter 2020 |  | 4th Quarter 2020
Revenue | $ | 465.0 |  |  | $ | 343.6 |  |  | $ | 376.1 |  |  | $ | 491.3 |
Net earnings (loss) attributable to shareholders | (63.8) |  |  | 286.2 |  |  | 55.9 |  |  | 504.2 |
Net earnings (loss) per share | (0.13) |  |  | 0.54 |  |  | 0.09 |  |  | 0.84 |
Diluted net earnings (loss) per share | (0.13) |  |  | 0.53 |  |  | 0.09 |  |  | 0.83 |
Adjusted Net Earnings 1 | 103.3 |  |  | 47.4 |  |  | 88.1 |  |  | 127.0 |
Adjusted Net Earnings per common share 1 | 0.19 |  |  | 0.09 |  |  | 0.15 |  |  | 0.21 |
Adjusted EBITDA 1 | 242.2 |  |  | 176.3 |  |  | 197.9 |  |  | 253.1 |
Total assets | 10,900.6 |  |  | 11,188.0 |  |  | 11,739.9 |  |  | 13,224.1 |
Long term debt 2 | 4,205.1 |  |  | 4,155.1 |  |  | 3,978.0 |  |  | 4,538.8 |
Dividend declared per common share | $ | 0.14 |  |  | $ | 0.16 |  |  | $ | 0.16 |  |  | $ | 0.16 |

1 | See Caution Concerning Non-GAAP Measures.
2 | Includes current portion of long-term debt, long-term debt and convertible debentures.

The quarterly results are impacted by various factors including seasonal fluctuations and acquisitions of facilities as noted in this MD&A.
Quarterly revenues have fluctuated between $343.6 million and $634.5 million over the prior two year period. A number of factors impact quarterly results including acquisitions, seasonal fluctuations, and winter and summer rates built into the PPAs. In addition, a factor impacting revenues year over year is the fluctuation in the strength of the Canadian dollar relative to the U.S. dollar which can result in significant changes in reported revenue from Canadian operations.
Quarterly net earnings attributable to shareholders have fluctuated between a loss of $63.8 million and earnings of $504.2 million over the prior two year period. Earnings have been significantly impacted by non-cash factors such as deferred tax recovery and expense, impairment of intangibles, property, plant and equipment and mark-to-market gains and losses on financial instruments.

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SUMMARY FINANCIAL INFORMATION OF ATLANTICA
The Company owns an approximately 44% beneficial interest in Atlantica. AQN accounts for its interest in Atlantica using the fair value method (see Note 8(a) in the annual consolidated financial statements). The summary financial information of Atlantica in the following table is derived from the consolidated financial statements of Atlantica as of December 31, 2021 and 2020 and for the years then ended which are reported in U.S. dollars and were prepared using International Financial Reporting Standards, as issued by the International Accounting Standards Board ("IFRS"). The recognition, measurement and disclosure requirements of IFRS differ from U.S. GAAP as applied by the Company.

(all dollar amounts in $ millions) | 2021 |  | 2020
Revenue | $ | 1,211.7 |  |  | $ | 1,013.3 |
Profit (loss) for the year | (10.9) |  |  | 16.9 |
Total non-current assets | 8,585.0 |  |  | 8,514.1 |
Total current assets | 1,166.9 |  |  | 1,424.3 |
Total non-current liabilities | 7,178.9 |  |  | 7,714.2 |
Total current liabilities | 824.4 |  |  | 483.3 |

DISCLOSURE CONTROLS AND PROCEDURES
AQN's management carried out an evaluation as of December 31, 2021, under the supervision of and with the participation of AQN’s Chief Executive Officer ("CEO") and Chief Financial Officer ("CFO"), of the effectiveness of the design and operations of AQN’s disclosure controls and procedures (as defined in Rule 13a-15(e) and Rule 15d-15(e) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”)). Based on that evaluation, the CEO and the CFO have concluded that as of December 31, 2021, AQN’s disclosure controls and procedures are effective to provide reasonable assurance that information required to be disclosed by AQN in reports that it files or submits under the Exchange Act is recorded, processed, summarized, and reported within the time periods specified in rules and forms of the U.S. Securities and Exchange Commission, and is accumulated and communicated to management, including the CEO and CFO, as appropriate, to allow timely decisions regarding required disclosure.
MANAGEMENT REPORT ON INTERNAL CONTROLS OVER FINANCIAL REPORTING
Management, including the CEO and the CFO, is responsible for establishing and maintaining internal control over financial reporting (as defined in Rules 13a-15(f) under the Exchange Act) to provide reasonable, but not absolute, assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with U.S. GAAP.
The Company's internal control over financial reporting framework includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the Company, (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with U.S. GAAP, and that receipts and expenditures of the Company are being made only in accordance with authorizations of management and directors of the Company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the Company's assets that could have a material effect on the Company's consolidated financial statements.
Management assessed the effectiveness of the Company's internal control over financial reporting as of December 31, 2021, based on the framework established in Internal Control - Integrated Framework (2013) issued by COSO. This assessment included review of the documentation of controls, evaluation of the design effectiveness of controls, testing of the operating effectiveness of controls, and a conclusion on this evaluation. Based on this assessment, management concluded that the Company's internal control over financial reporting was effective as of December 31, 2021 to provide reasonable assurance regarding the reliability of financial reporting and the preparation of consolidated financial statements for external reporting purposes in accordance with U.S. GAAP. Management reviewed the results of its assessment with the Audit Committee of the Board of Directors of AQN.
CHANGES IN INTERNAL CONTROLS OVER FINANCIAL REPORTING
For the twelve months ended December 31, 2021, there has been no change in the Company’s internal controls over financial reporting that has materially affected, or is reasonably likely to materially affect, the Company’s internal controls over financial reporting.

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INHERENT LIMITATIONS ON EFFECTIVENESS OF CONTROLS
Due to its inherent limitations, disclosure controls and procedures or internal control over financial reporting may not prevent or detect all misstatements based on error or fraud. Further, the effectiveness of internal control is subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with policies or procedures may change.
CRITICAL ACCOUNTING ESTIMATES AND POLICIES
AQN prepared its consolidated financial statements in accordance with U.S. GAAP. The preparation of the consolidated financial statements requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, related amounts of revenues and expenses, and disclosure of contingent assets and liabilities. Significant areas requiring the use of management judgment relate to the scope of consolidated entities, useful lives and recoverability of depreciable assets, the measurement of deferred taxes and the recoverability of deferred tax assets, rate-regulation, unbilled revenue, pension and post-employment benefits, fair value of derivatives and fair value of assets and liabilities acquired in a business combination. Actual results may differ from these estimates.
AQN’s significant accounting policies and new accounting standards are discussed in Notes 1 and 2 in the annual consolidated financial statements, respectively. Management believes the following accounting policies involve the application of critical accounting estimates. Accordingly, these accounting estimates have been reviewed and discussed with the Audit Committee of the Board of Directors of AQN.
Consolidation and Variable Interest Entities
The Company uses judgment to assess whether its operations or investments represent variable interest entities ("VIEs"). In making these evaluations, management considers (a) the sufficiency of the investment's equity at risk, (b) the existence of a controlling financial interest, and (c) the structure of any voting rights. In addition, management considers the specific facts and circumstances of each investment in a VIE when determining whether the Company is the primary beneficiary. The factors that management takes into consideration include the purpose and design of the VIE, the key decisions that affect its economic performance, whether the parties to the arrangements are related parties or defacto agents of the Company, and whether the Company has the power to direct the activities that would most significantly affect the economic performance of the VIE. Management's judgment is also required to determine whether the Company has the right to receive benefits or the obligation to absorb losses of the VIE. Based on the judgments made, the Company will consolidate the VIE if it determines that it is the primary beneficiary.
Estimated Useful Lives and Recoverability of Long-Lived Assets, Intangibles and Goodwill
The Company makes judgments (a) to determine the recoverability of a development project, and the period over which the costs are capitalized during the development and construction of the project, (b) to assess the nature of the costs to be capitalized, (c) to distinguish individual components and major overhauls, and (d) to determine the useful lives or unit-of-production over which assets are depreciated.
Depreciation rates on most utility assets are subject to regulatory review and approval, and depreciation expense is recovered through rates set by ratemaking authorities. The recovery of those costs is dependent on the ratemaking process.
The carrying value of long-lived assets, including intangible assets and goodwill, is reviewed whenever events or changes in circumstances indicate that such carrying values may not be recoverable, and at least annually for goodwill. Some of the factors AQN considers as indicators of impairment include a significant change in operational or financial performance, unexpected outcome from rate orders, natural disasters, energy pricing and changes in regulation. When such events or circumstances are present, the Company assesses whether the carrying value will be recovered through the expected future cash flows. If the facility includes goodwill, the fair value of the facility is compared to its carrying value. Both methodologies are sensitive to the forecasted cash flows and in particular energy prices, long-term growth rate and, discount rate for the fair value calculation.
In 2021 and 2020, management assessed qualitative and quantitative factors for each of the reporting units that were allocated goodwill. No goodwill impairment provision was required.

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Valuation of Deferred Tax Assets
In assessing the realization of deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized and provides any necessary valuation allowances as required. Management evaluates the probability of realizing deferred tax assets by reviewing a forecast of future taxable income together with management's intent and ability to implement tax planning strategies, if necessary, to realize deferred tax assets. Although at this time management considers it more likely than not that it will have sufficient taxable income to realize the deferred tax assets, there can be no assurance that the Company will generate sufficient taxable income in the future to utilize these deferred tax assets. Management also assesses the ability to utilize tax attributes, including those in the form of carryforwards, for which the benefits have already been reflected in the financial statements.
Accounting for Rate Regulation
Accounting guidance for regulated operations provides that rate-regulated entities account for and report assets and liabilities consistent with the recovery of those incurred costs in rates if the rates established are designed to recover the costs of providing the regulated service and if the competitive environment makes it probable that such rates can be charged and collected. This accounting guidance is applied to the Regulated Services Group's operations, with the exception of ESSAL.
Certain expenses and revenues subject to utility regulation or rate determination normally reflected in income are deferred on the balance sheet as regulatory assets or liabilities and are recognized in income as the related amounts are included in service rates and recovered from or refunded to customers. Regulatory assets and liabilities are recorded when it is probable that these items will be recovered or reflected in future rates. Determining probability requires significant judgment on the part of management and includes, but is not limited to, consideration of testimony presented in regulatory hearings, proposed regulatory decisions, final regulatory orders and industry practice. If events were to occur that would make the recovery of these assets and liabilities no longer probable, these regulatory assets and liabilities would be required to be written off or written down.
Unbilled Energy Revenues
Revenues related to natural gas, electricity and water delivery are generally recognized upon delivery to customers. The determination of customer billings is based on a systematic reading of meters throughout the month. At the end of each month, amounts of natural gas, energy or water provided to customers since the date of the last meter reading are estimated, and the corresponding unbilled revenue is recorded. Factors that can impact the estimate of unbilled energy include, but are not limited to, seasonal weather patterns compared to normal, total volumes supplied to the system, line losses, economic impacts, and composition of customer classes. Estimates are reversed in the following month and actual revenue is recorded based on subsequent meter readings.
Derivatives
AQN uses derivative instruments to manage exposure to changes in commodity prices, foreign exchange rates, and interest rates. Management’s judgment is required to determine if a transaction meets the definition of a derivative and, if it does, whether the normal purchases and sales exception applies or whether individual transactions qualify for hedge accounting treatment. Management’s judgment is also required to determine the fair value of derivative transactions. AQN determines the fair value of derivative instruments based on forward market prices in active markets obtained from external parties adjusted for nonperformance risk. A significant change in estimate could affect AQN’s results of operations if the hedging relationship was considered no longer effective.
Pension and Post-employment Benefits
The obligations and related costs of defined benefit pension and post-employment benefit plans are calculated using actuarial concepts, which include critical assumptions related to the discount rate, mortality rate, compensation increase, expected rate of return on plan assets and medical cost trend rates. These assumptions are important elements of expense and/or liability measurement and are updated on an annual basis, or upon the occurrence of significant events. The Company used the new mortality improvement scale (MP-2021) recently released by the Society of Actuaries adjusted to reflect the 2021 Social Security Administration ultimate improvement rates.
The sensitivities of key assumptions used in measuring accrued benefit obligations and benefit plan cost for 2021 are
outlined in the following table. They are calculated independently of each other. Actual experience may result in changes
in a number of assumptions simultaneously. The types of assumptions and method used to prepare the sensitivity analysis
has not changed from previous periods and is consistent with the calculation of the retirement benefit obligations and net
benefit plan cost recognized in the consolidated financial statements.

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| 2021 Pension Plans |  | 2021 OPEB Plans
(all dollar amounts in $ millions) | Accrued Benefit Obligation | Net Periodic Pension Cost |  | Accumulated Postretirement Benefit Obligation | Net Periodic Postretirement Benefit Cost
Discount Rate |  |  |  |  |
1% increase |  | (80.4) |  |  | (5.4) |  |  |  | (42.6) |  |  | (3.5) |
1% decrease |  | 99.2 |  |  | 6.6 |  |  |  | 55.2 |  |  | 4.8 |
Future compensation rate |  |  |  |  |
1% increase |  | 3.3 |  |  | 2.0 |  |  |  | 9.0 |  |  | 1.0 |
1% decrease |  | (2.9) |  |  | (1.9) |  |  |  | (8.0) |  |  | (1.0) |
Expected return on plan assets |  |  |  |  |
1% increase |  | — |  |  | (6.1) |  |  |  | — |  |  | (1.8) |
1% decrease |  | — |  |  | 6.1 |  |  |  | — |  |  | 1.8 |
Health care trend |  |  |  |  |
1% increase |  | — |  |  | — |  |  |  | 47.3 |  |  | 7.6 |
1% decrease |  | — |  |  | — |  |  |  | (38.6) |  |  | (5.8) |

Business Combinations
The Company has completed a number of business combinations in the past few years. Management's judgment is required to estimate the purchase price, to identify and to fair value all assets and liabilities acquired. The determination of the fair value of assets and liabilities acquired is based upon management’s estimates and certain assumptions generally included in a present value calculation of the related cash flows.
Acquired assets and liabilities assumed that are subject to critical estimates include property, plant and equipment, regulatory assets and liabilities, intangible assets, long-term debt and pension and OPEB obligations. The fair value of regulated property, plant and equipment is assessed using an income approach where the estimated cash flows of the assets are calculated using the approved tariff and discounted at the approved rate of return. The fair value of ESSAL's property, plant and equipment was assessed using a multi-period excess earnings method. The fair value of regulatory assets and liabilities considers the estimated timing of the recovery or refund to customers through the rate making process. The fair value of intangible assets is assessed using a multi-period excess earnings method. The fair value of long-term debt is determined using a discounted cash flow method and current interest rates. The pension and OPEB obligations are valued by external actuaries using the guidelines of ASC 805, Business combinations.

Algonquin Power & Utilities Corp. - Management Discussion & Analysis |